Fortnightly - Order No. 636http://www.fortnightly.com/tags/order-no-636
enZone of Reasonablenesshttp://www.fortnightly.com/fortnightly/2011/07/zone-reasonableness
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Coping with rising profitability, a decade after restructuring.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Jeff D. Makholm and Kurt G. Strunk</p>
</div></div></div><div class="field field-name-field-import-category field-type-text field-label-inline clearfix"><div class="field-label">Category:&nbsp;</div><div class="field-items"><div class="field-item even">Energy Risk &amp; Markets</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>Jeff D. Makholm</b> is a senior vice president at National Economic Research Associates Inc. (NERA), and <b>Kurt G. Strunk</b> is a senior consultant.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - July 2011</div></div></div><div class="field field-name-field-import-image field-type-image field-label-above"><div class="field-label">Image:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/article_images/1107/images/1107-ERM-fig1.jpg" width="1375" height="1252" alt="" /></div><div class="field-item odd"><img src="http://www.fortnightly.com/sites/default/files/article_images/1107/images/1107-ERM-fig2.jpg" width="1375" height="1252" alt="" /></div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>During the past three years, the Federal Energy Regulatory Commission (the FERC) has initiated five investigations into the justness and reasonableness of interstate gas pipeline rates.<sup>1</sup> Under the Natural Gas Act of 1938 (the NGA), the FERC has a statutory obligation to assure that such pipelines rates are just and reasonable. Case precedent makes clear that no single just and reasonable rate exists for a given pipeline at a given time; instead, for rates to meet the just and reasonable standard, they must remain within a zone of reasonableness. In judicial review of its decisions, the courts have held the FERC to an end result within that zone.<sup>2</sup> The FERC initiated the examination of these five pipelines’ rates precisely because their Form 2 financial data appeared to indicate excessive profitability falling outside that zone.</p>
<p>For interstate gas pipelines, the passage of time can lead to rates that exceed the cost of service because traditional ratemaking is front-loaded by the nature of straight-line depreciation of pipeline investments. Such is particularly true for gas pipelines since the FERC invoked the standard of “incremental” pricing for new capacity additions, which effectively segregates the cost of service for new projects from the pipeline property that supports existing shipper capacity entitlements.<sup>3</sup> Without the need to invest in new pipeline equipment to support existing capacity contracts, the passage of time will drive down the rate base supporting existing contracts through depreciation. This in turn lowers the financing charges associated with carrying the rate base, and therefore lowers the cost of service.<sup>4</sup> Traditional ratemaking, however, requires that rates stay constant in dollar terms until the next rate case. In the period before the restructuring of pipeline regulation was completed in about 2000, the FERC required pipelines to file periodic NGA Section 4 rate cases to assure that rates didn’t stray too far from the cost of service. With the implementation of open access, incremental pricing and competitive gas transport culminating in Order Nos. 636<sup>5</sup> and 637,<sup>6</sup> however, FERC eliminated the ongoing requirement for pipelines to file regular Section 4 rate cases.</p>
<p>The elimination of periodic rate cases places a greater burden on shippers to monitor the rates they pay (under their capacity contracts) and on the FERC itself to screen pipeline returns and to identify excessive returns. While the FERC may have hoped that its competition-friendly policies, which include allowing pipelines to adopt alternative ratemaking practices and to negotiate rates with their customers,<sup>7</sup> would allow shippers and the pipeline to find a set of mutually-agreeable rates and limit the need for litigated proceedings, FERC’s oversight responsibilities are as important today as they ever have been. Although FERC’s 1996 policy statement did envision that some pipelines would be able to meet the criteria for market-based rates, no pipeline to date has been able to meet those criteria. Indeed, the one pipeline that made an attempt to apply for the loosened regulation of rates was shot down by the FERC with such finality—on the subject of the inherent market power of pipelines over captive customers—that no other pipeline has tried again.<sup>8</sup> The FERC thus continues to be the judge of just and reasonable rates when shippers and pipelines are unable to find mutually-agreeable solutions. While many pipelines now have an incentive to delay scrutiny of their rates and cost of service for as long as possible, the declining rate base phenomenon makes it important for shippers and the FERC to monitor pipeline profits judiciously to assure that rates and costs don’t unduly diverge.</p>
<p>How does the FERC decide whether to initiate an investigation to determine whether a given pipeline’s rates fall outside the zone of reasonableness? The screen that the FERC uses is the earned return on common equity (ROE), as indicated by the data submitted by pipelines in Forms 2 and 2-A. Because many variables are at play in a detailed rate case review, however, the earned returns implied by Forms 2 and 2-A can only serve as initial indicators of profitability and a signal as to whether a more detailed review of cost and revenue is necessary.</p>
<h4>Earned Returns</h4>
<p>To assess the ROE for 2010, the rates and cost of service for 68 interstate gas pipelines with gas plant exceeding $200 million were analyzed in a four-step process: 1) Estimate the pipeline’s revenue requirement using traditional cost-of-service ratemaking techniques, excluding ROE and income taxes. The revenue requirement includes standard expense items such as depreciation, operation and maintenance costs, interest, other taxes and administrative and general costs. The pipelines report these directly on Form 2.<sup>9</sup> They also report on Form 2 the asset account balances needed to determine the pipeline’s rate base. 2) Calculate pre-tax net income by subtracting the estimated revenue requirement from actual revenues. 3) Calculate after-tax net income by subtracting income taxes from pre-tax net income, using the pipeline’s composite tax rate. 4) Calculate ROE by dividing after-tax net income by the amount of common equity in rate base.</p>
<p>Because the ROE is highly sensitive to the level of equity permitted in the capital structure, and further because many pipelines that are as subsidiaries of larger holding companies have unusual capital structures by regulatory standards, the ROEs were calculated using both the reported capital structure and under the assumption that the FERC would require that the pipeline set rates based on a hypothetical capital structure containing 50 percent equity<sup>10</sup><em>(See Figures 1 and 2)</em>.</p>
<p>The largest allowed return on equity given by FERC to any pipeline in the last decade is 14 percent.<sup>11</sup> As a result, this screening of pipelines’ ROE suggests that rates of return for many pipelines not yet investigated by FERC may be well outside the zone of reasonableness. That FERC has initiated investigations of only a handful of pipelines is surprising in light of these data. The returns on equity that triggered the five rate investigations all exceeded 20 percent—averaging 26 percent, almost double the FERC’s largest recent granted ROE.</p>
<p>As Figure 2 indicates, a limited number of pipelines have achieved very low levels of return—in some cases negative. This phenomenon is partly the result of negotiated rates that levelize pricing for shippers, and back-load the return to equity investors. FERC’s 1996 policy statement on pipeline pricing encouraged the use of negotiated rates, and levelized ratemaking has been accepted by FERC for a number of pipelines.</p>
<p>It’s only fair to judge any such presentation of ROEs against the underlying risk to which such equity is applied, which is how the capital markets evaluate the adequacy of returns. Equity investments are by nature contingent claims; equity investors receive returns from their investments only after debt holders have received their contractual interest payments. Capital structures employing high levels of debt subject equity investors to more financial risk than capital structures with less debt. All other things being equal, high levels of financial risk increase the required rate of return for equity investors. The FERC recognizes this fact when exercising its ratemaking authority. For example, the FERC has repeatedly granted a 14 percent rate of return on equity for “greenfield” pipelines whose equity investors not only face development risk, but also significant financial risk—<i>e.g.</i>, with debt comprising 70 percent of committed capital—while granting lower rates of return for pipelines with less debt leverage. To evaluate whether a given return on equity is excessive, one must consider not only the business risks that equity investors confront, but also the financial risk. Capital structure is therefore a pivotal variable in assessing whether the current profits accruing to equity investors lie within a zone of reasonableness.</p>
<p>The FERC’s policy on capital structure is to try to rely on actual verifiable data: that is, on a pipeline’s actual capital structure when the pipeline raises its capital directly or otherwise on the parent company’s capital structure. The FERC will only turn to a hypothetical capital structure if it deems that the level of equity is unreasonably high, particularly with reference to observed capital structures in a group of stand-alone pipelines that it concludes are comparable to the pipeline in question.<sup>12</sup> Thus on numerous occasions the commission rejected high equity ratios proposed by a pipeline and assumed a reasonable use of debt capital.<sup>13</sup></p>
<h4>Why Returns Increase</h4>
<p>Although declining rate base goes far in explaining many pipelines’ steadily increased returns, natural gas market dynamics have also helped their financial results to remain strong. In 2010, domestic natural gas production and consumption reached record levels. These records reflect a long-term trend of strong growth in natural gas demand that began in the mid-1980s. Since then, natural gas has become the fuel of choice for much of the nation’s new electricity generation. Further, natural gas demand for residential, commercial and industrial uses has also grown. In the United States, gas-on-gas competition—that is, competition among different sources of gas including traditional gas sources, shale gas and LNG—has kept prices down, while prices for other hydrocarbons have risen considerably. The favorable market dynamics in natural gas have allowed most pipelines to remain fully-subscribed (with capacity contracts) and to maintain high utilization factors.<sup>14</sup> Of course, regional differences in the supply-demand balance, additions of new pipeline capacity, and storage additions naturally lead some pipelines to fare better than others.</p>
<p>Pipeline investors believe the strong growth in natural gas supply and demand will continue. Consequently, they have begun a wave of new pipeline construction across the country. A recent industry report by the Department of Energy’s Energy Information Administration explains the growth trend:</p>
<p>Favorable market and regulatory conditions explain why many pipeline investors are doing so well in spite of the economic downturn and lower overall interest rate environment. In such an investment environment, reliable gas pipeline rate base is a highly attractive asset—particularly if ROEs automatically trend upward over time without attention from the FERC or the groups holding the bulk of capacity contracts (gas utilities or power plants).</p>
<h4>FERC Remedies</h4>
<p>Under NGA Section 5, the FERC can initiate an investigation of pipeline rates on its own motion or “upon complaint of any State, municipality, State commission, or gas distributing company.”<sup>16</sup> However, there are significant limitations under Section 5 of the <i>Natural Gas Act</i> that significantly limit its effectiveness in remedying unjust and unreasonable pipeline rates.</p>
<p>A Section 5 proceeding is very different than the typical rate increase case that a pipeline files under Section 4. The most critical difference is that any rate reduction under Section 5 will take place prospectively only, either upon the date of a FERC decision of the appropriate rate or a FERC order approving a negotiated settlement rate. A Section 4 proceeding, by contrast, automatically adopts the newly-filed pipeline rates no later than five months after filing, with a refund (one way or the other) once the FERC makes its final determination.</p>
<p>Because of the limitations of Section 5, pipelines have inherent financial incentives to delay resolutions of Section 5 proceedings—and corresponding disincentives to settle cases. While there may be costs the pipeline incurs in litigation, they are typically much more than offset by reduced rates made effective sooner than in a fully-litigated case. A related effect is that any rates agreed on in settlement of a Section 5 investigation generally include a premium to the pipeline as an inducement to allow a reduction in rates to take effect sooner than would otherwise occur.</p>
<p>Other than the existing asymmetry with respect to ratemaking relief, there’s one other important difference between Section 5 and Section 4 proceedings. By regulation and precedent, rates in a Section 4 proceeding are determined based on costs incurred and revenues received during a defined 12-month test period. In contrast, there are no regulations, nor any reliable precedents, defining the specific cost period to be used to determine the appropriate rates in a Section 5 proceeding. The FERC at the outset of a Section 5 proceeding typically requires a pipeline to file a cost and revenue study using the most recent 12-month period for which data is available. However, the FERC also allows the pipeline to propose adjustments to the historical data.<sup>17</sup> The absence of clear guidance disadvantages a pipeline customer, as it invites complication in the development of an evidentiary record and gives the pipeline the opportunity to provide evidence on costs and revenues from different time periods to justify existing rates. Overall, there are many FERC-regulated pipelines that are earning rates of return well in excess of that which would be allowed in a litigated proceeding, and yet they haven’t been subject to any investigation under Section 5. The inherent obstacles associated with pursuing rate reductions under NGA Section 5 help to explain why.</p>
<p>There are only two instances within the last 10 years in which a complaint was filed by customers or a state commission that prompted the FERC to initiate a Section 5 investigation into the existing rates of a pipeline—one against National Fuel Gas Supply<sup>18</sup> and the other against Southwest Gas Storage.<sup>19</sup> In both instances, the FERC granted the request of the complainant to initiate an investigation by directing the pipeline to file a cost and revenue study for the most recent 12-month period. However, in both proceedings, customers were significantly disadvantaged by the limitations of Section 5.</p>
<p>In <i>National Fuel</i>, the FERC rejected a request by customers to reduce immediately the fuel retention factor of the pipeline, based on an argument that the existing fuel factor had over-recovered fuel by substantial amounts based on pipeline-supplied data for a recent 12-month period.<sup>20</sup> Customers eventually achieved a settlement that reduced in substantial part the over-recovery of fuel, but left the non-fuel (or “base rate”) elements of the pipeline’s rates unchanged.</p>
<p>In <i>Southwest Storage</i>, the commission rejected a motion for waiver of the administrative law judge’s initial decision and motions for an immediate, interim reduction in rates.<sup>21</sup> Customers negotiated a settlement that provided for no change in any of the pipeline’s rates.</p>
<p>Ultimately, the FERC seems to have the power to order interim relief in particular cases. But such Section 5 relief sought by gas distributors, state commissions or the FERC itself requires evidence and argument on the part of those parties asking for relief that must compete with counter-evidence and argument brought by pipelines. In contrast, the timing of Section 4 relief for pipeline companies is automatic. Given the perceived shortcomings of Section 5, Congress faces pressure to amend it and allow for refunds on a retrospective basis.<sup>22</sup></p>
<h4>Zone of Reasonableness</h4>
<p>When <i>prima facie</i> indicators suggest that rates are outside the zone of reasonableness for interstate pipelines, the customers of those pipelines should press the FERC to act to protect the public interest and engage the pipelines in detailed rate reviews. The level of earned returns for the pipeline sector today calls for more rate scrutiny and additional activity before the FERC.</p>
<p>The lack of periodic Section 4 rate cases, as in the old days before regulatory restructuring for this industry, means that shippers and the FERC must more be diligent in monitoring pipelines’ financial results. Legislative changes would improve the ability of FERC to ensure that shippers of natural gas on interstate pipelines pay just and reasonable rates. Absent legislative changes to broaden FERC authority under NGA Section 5, however, it will take significant collective shipper efforts, and a determined FERC, to assure that gas transportation rates remain just and reasonable.</p>
<p> </p>
<h4>Endnotes:</h4>
<p>1. See: Ozark Gas Transmission LLC, 133 FERC ¶ 61,158 (2010); Kinder Morgan Interstate Gas Transmission LLC, 133 FERC ¶ 61,157 (2010), reh’g granted in part and denied in part, 134 FERC ¶ 61,061 (2011); Natural Gas Pipeline Co., 129 FERC ¶ 61,158 (2009), reh’g denied, 130 FERC ¶61,133 (2010); Northern Natural Gas Co., 129 FERC ¶ 61,159 (2009), reh’g denied, 130 FERC ¶ 61,134 (2010); Great Lakes Gas Transmission Limited Partnership, 129 FERC ¶ 61,160 (2009), reh’g denied, 130 FERC ¶ 61,132 (2010).</p>
<p>2. See: Permian Basin, 390 U.S. at 797, 88 S.Ct. 1344; Pub. Serv. Comm’n of Ky., 397 F.3d at 1009.</p>
<p>3. See: “Policy Statement on Determination of Need,” 1902-AB86, FERC Docket No. PL-3-000.</p>
<p>4. Many variables determine a pipeline’s cost of service. The passage of time doesn’t always lead to a decline in the cost of service for certain contracted capacity, particularly for pipelines requiring major capital improvements to existing infrastructure. In addition, some pipelines may seek to levelize their rates over a given time period, which would affect year-by-year ROE calculations.</p>
<p>5. 59 FERC ¶ 61,030, 18 CFR Part 284 (Order No. 636), April 8, 1992.</p>
<p>6. 90 FERC ¶ 61,109, CFR Parts 154, 161, 250, and 254 (Order No. 637), Feb. 9, 2000.</p>
<p>7. See: “Alternatives to Traditional Cost-of-Service Ratemaking for Natural Gas Pipelines,” 74 FERC ¶ 61076, 1996.</p>
<p>8. “Koch has not met the requirements of the Policy Statement and has not shown that it lacks market power.” Docket No. RM-95-6-000, Order Reversing Initial Decision, p. 23.</p>
<p>9. The data for this study were obtained through SNL Financial. Form 2 data for Accounts 117.1, 117.2, 283, “Fuel Recoveries and Commercial and Industrial Sales,” weren’t available through SNL and are excluded from the analysis.</p>
<p>10. This assumption is consistent with the commission’s representative ruling in Ingleside Energy Center, rejecting the use of a 70 percent equity ratio proposed by the developer and required that a 50/50 debt-to-equity capital structure be used for ratemaking purposes. See 112 FERC ¶ 61101, 2005.</p>
<p>11. This 14 percent return on equity was allowed for greenfield pipelines with substantial financial leverage such as Colorado Interstate Gas Co (Docket No. CP03-7), AES Ocean Express (Docket No. CP02-90), Sonora Pipeline LLC (Docket No. CP07-74), Trans-Union Interstate Pipeline (Docket No. CP01-37) and Tractebel Calypso Pipeline (Docket No. CP01-409).</p>
<p>12. The Commission has found that “a large equity ratio is more costly to ratepayers, since equity financing is typically more costly than debt financing, and also because the interest on indebtedness is tax deductible.” See <i>Ingleside Energy Center</i>, 112 FERC ¶ 61101, 2005.</p>
<p>13. See, <i>e.g.</i>, Schneidewind v. ANR Pipeline Co., 485 U.S. 293, 302 (1988) (“Thus, FERC exercises its ratemaking authority to limit the burden on ratepayers of abnormally high equity ratios.”); <i>Transcontinental Gas Pipe Line Corp.</i>, 71 FERC ¶61,305 (1995) (“[t]he determination of an appropriate capital structure involves a balancing of the investor and consumer interests. Equity generally costs more than debt. Hence, ratepayers would be subjected to an excessive burden if their rates had to be set at a level high enough to compensate the pipeline for excessive equity in its capital structure. This burden on ratepayers can be limited by ‘levering a capital structure with lower-cost debt.’”)</p>
<p>14. The imposition of ratemaking based on contract levels, rather than flowing volumes, makes pipeline revenues highly predictable for pipelines that are fully-subscribed with such contracts, which is the case for most interstate pipeline capacity.</p>
<p>15. <i>Expansion of the U.S. Natural Gas Pipeline Network: Additions in 2008 and Projects through 2011</i>, Energy Information Administration, Office of Oil and Gas, September 2009.</p>
<p>16. <i>Natural Gas Act</i> of 1938, 52 Stat., pp. 823.</p>
<p>17. Kinder Morgan Interstate Gas Transmission LLC, 133 FERC ¶61,157 (2010), reh’g granted in part and denied in part, 134 FERC ¶61,061 (2011).</p>
<p>18. <i>Public Service Comm’n of N.Y. v. National Fuel Gas Supply</i>, 115 FERC ¶61,299 (2006).</p>
<p>19. <i>Panhandle Complainants, v. Southwest Gas Storage Company</i>, 117 FERC ¶61,318 (2006).</p>
<p>20. Public Service Comm’n of N.Y. v. National Fuel Gas Supply, supra.</p>
<p>21. Panhandle Complainants, v. Southwest Gas Storage Co., 120 FERC ¶61,207 (2007).</p>
<p>22. The Senate Energy &amp; Natural Resources Committee examined NGA reform and voted in June 2009 to reject an amendment that would have modified <i>Natural Gas Act</i> Section 5 to provide the FERC with the authority to grant refunds to consumers that are paying unjust and unreasonable pipeline rates. In 2010, however, FERC Chairman Jon Wellinghoff continued to communicate his support for legislative changes to the evident asymmetry between Section 4 and Section 5 remedies under the NGA. See: 131 FERC ¶61,178 (dissenting opinion to an order issued May 27, 2010, in Docket No. RP10-148-000, Issued June 8, 2010).</p>
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<a href="/tags/aes">AES</a><span class="pur_comma">, </span><a href="/tags/capital-structure">Capital structure</a><span class="pur_comma">, </span><a href="/tags/commission">Commission</a><span class="pur_comma">, </span><a href="/tags/congress">Congress</a><span class="pur_comma">, </span><a href="/tags/cost">Cost</a><span class="pur_comma">, </span><a href="/tags/department-energy">Department of Energy</a><span class="pur_comma">, </span><a href="/tags/energy-information-administration-0">Energy Information Administration</a><span class="pur_comma">, </span><a href="/tags/federal-energy-regulatory-commission">Federal Energy Regulatory Commission</a><span class="pur_comma">, </span><a href="/tags/federal-energy-regulatory-commission-ferc">Federal Energy Regulatory Commission (FERC)</a><span class="pur_comma">, </span><a href="/tags/ferc">FERC</a><span class="pur_comma">, </span><a href="/tags/jon-wellinghof">Jon Wellinghof</a><span class="pur_comma">, </span><a href="/tags/jon-wellinghoff-0">Jon Wellinghoff</a><span class="pur_comma">, </span><a href="/tags/national-fuel-gas">National Fuel Gas</a><span class="pur_comma">, </span><a href="/tags/national-fuel-gas-supply">National Fuel Gas Supply</a><span class="pur_comma">, </span><a href="/tags/natural-gas-act-1938">Natural Gas Act of 1938</a><span class="pur_comma">, </span><a href="/tags/network">Network</a><span class="pur_comma">, </span><a href="/tags/nga">NGA</a><span class="pur_comma">, </span><a href="/tags/nga-section-5">NGA Section 5</a><span class="pur_comma">, </span><a href="/tags/order-no-636">Order No. 636</a><span class="pur_comma">, </span><a href="/tags/order-no-637">Order No. 637</a><span class="pur_comma">, </span><a href="/tags/ratemaking">Ratemaking</a><span class="pur_comma">, </span><a href="/tags/roe">ROE</a><span class="pur_comma">, </span><a href="/tags/southwest-gas-storage">Southwest Gas Storage</a><span class="pur_comma">, </span><a href="/tags/storage">storage</a><span class="pur_comma">, </span><a href="/tags/transco">Transco</a><span class="pur_comma">, </span><a href="/tags/transmission">Transmission</a> </div>
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Fri, 01 Jul 2011 04:00:00 +0000puradmin13536 at http://www.fortnightly.comPipelines: Are Regulators in for the Long Haul?http://www.fortnightly.com/fortnightly/2005/07/pipelines-are-regulators-long-haul
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>An economic perspective on long-term contracting for gas pipeline service.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Ken Costello</p>
</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Kenneth W. Costello is the senior institute economist at the National Regulatory Research Institute. He may be reached at 614-292-2831, or by e-mail at <a href="mailto:Costello.l@osu.edu">Costello.l@osu.edu</a>.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - July 2005</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>Predictably, pipelines and other industry stakeholders are among the biggest supporters of long-term contracting for pipeline services, as they try to make life easier for themselves.<sup>1</sup> In its 2003 natural gas study <em>Balancing Natural Gas Policy— Fueling the Demands of a Growing Economy</em>, the National Petroleum Council (NPC), mainly an industry group, argues that long-term contracts are essential for stimulating adequate investments in gas pipelines needed to meet future natural gas demand. The study points out that 75 percent of pipeline contracts, which are mostly long term, will expire by the end of 2008. NPC is predicting that new contracts will be much shorter in duration, to a large extent the result of state commission policies that allegedly frown upon long-term contracts. The NPC calls for state regulators to reassess the environment that they have created through their past actions and policies (which the NPC characterized as “regulatory barriers”)—namely, one where gas utilities are reluctant to sign long-term contracts because of the fear that they will be financially penalized if events turn out unfavorably.</p>
<p>Last year’s study, <em>An Updated Assessment of Pipeline and Storage Infrastructure for the North American Gas Market</em>, funded by the Interstate Natural Gas Association of America (INGAA) Foundation, echoes the NPC concerns. The study mirrors the views of pipelines in Federal Energy Regulatory Commission (FERC) proceedings and other forums, specifically recommending that state commissions reassess their policies that “discourage [gas utilities] from entering into long-term capacity contracts for transportation and storage that are necessary to underpin new infrastructure projects.” These policies pertain to retroactive prudence reviews and support for “increasing the competitiveness of third-party marketers.” The study also argues that long-term contracts can help to compensate pipelines for being precluded from capturing the market value of transportation in their rates during peak periods. (Pipelines, for a number of years, have argued before FERC that they are forced by market pressures to discount prices below tariff levels during off-peak periods.)</p>
<p>The study faults FERC for not recognizing the risks that pipelines face from the dearth of long-term contracts when setting a rate of return. The study correctly observes that shippers, whether regulated entities or not, have been less willing to commit themselves to long-term contracts. But the serious problem, as articulated in the study, is that the reluctance of shippers to sign long-term contracts significantly will stifle support for new pipeline projects.</p>
<p>FERC has come down on the issue by expressing, at least in one report (<em>State of the Markets Report</em>) that long-term contracting is crucial in evoking additional pipeline capacity. The same report acknowledges that gas utilities rationally are responding to market conditions by not committing to long-term pipeline capacity because, for example, of the uncertainty caused by retail unbundling. The report also stated that “pipeline investment appeared to be appropriate given basis signals.”</p>
<p>Over the years, FERC policy has evolved to where it now does not require shipper commitment in certifying new pipeline facilities. In its 1999 Certificate Policy Statement, FERC required that an applicant demonstrate that public benefits exceed adverse effects, in addition to showing that new pipeline capacity can be financially supported <em>without relying on subsidization from existing customers</em> (emphasis added). Showing market demand for the new capacity, in the absence of long-term contracts with shippers, can suffice as a means to receive FERC approval.</p>
<p>Of course, long-term contracts with shippers for a significant portion of new capacity would indisputably demonstrate the need for new capacity; but it is not a requisite for receiving certification. One important indicator of demand, recognized by FERC, is the basis differential between market centers/hubs (specifically, basis differentials in excess of long-run marginal cost would signal the commercial viability of additional pipeline capacity).</p>
<p>As an aside, as long as adequate pipeline capacity is available in a region, the tendency of shippers would be to transact on a shorter-term basis for nonfirm capacity (for interruptible service, as an example, the shipper could avoid paying demand charges). When regional capacity starts to tighten, however, the same shippers would be more willing to go longer term, as well as to sign up for firm service, in their pipeline capacity purchases. This would signal to pipelines that additional capacity is required.</p>
<p>A 2002 Keystone Center report, <em>Expanding Natural Gas Pipeline Infrastructure to Meet the Growing Demand for Cleaner Power</em>, summarizing a policy dialogue among industry stakeholders and policymakers (including gas pipelines), concluded that “participants found that FERC’s current policy on the certification of new interstate natural gas pipeline facilities provides an appropriate balance between, on the one hand, regulatory oversight to protect against the adverse consequences of overbuilding and, on the other, market-oriented philosophies that will allow <em>the infrastructure to grow with the market</em>” (emphasis added).</p>
<p>The report also says “FERC’s policy statement [on certification of new pipeline facilities] provides a number of incentives for pipelines to plan for and construct the optimal level of capacity.” In other words, the consensus was that FERC’s certification criteria seem to pose no special barrier in expanding economically-justified pipeline capacity.</p>
<p>The collective arguments of supporters of long-term contracting can be summarized as follows:</p>
<p>• Unless we see more long-term contracting, new investments in pipeline capacity will be deficient. Specifically, as pipelines have become susceptible to higher market risk, they may be prevented from receiving the necessary financing from Wall Street. Especially with the “turnback” of large amounts of capacity under expired contracts, pipelines have argued that the trend toward shorter-term contracts will become even more pronounced in the future.</p>
<p>• Regulatory uncertainty at the state level discourages gas utilities from signing long-term contracts. The threat of hindsight review imposes the risk of stranded costs that would tend to shift utilities’ preference toward shorter-term transactions.</p>
<p>• State commissions should recognize the importance of long-term contracts in a local gas utility’s supply and transportation portfolio.</p>
<p>• FERC’s pricing practices artificially have inflated shorter-term transactions by shippers. For example, pipelines have argued that market forces require them to discount rates below tariff levels for released capacity and short-term and interruptible service, while longer-term transactions largely are priced on the basis of rigid cost-of-service principles.</p>
<p>• More than anything, regulation can be blamed for the deficiency of long-term contracts, which in the long run may jeopardize the expansion of sufficient new pipeline capacity to meet future gas demand.</p>
<h4>The Economics of Long-Term Contracting</h4>
<p>There are three distinct categories of transactions: spot, longer-term contracts, and internal organization. The last occurs when a firm is vertically integrated and looks to itself rather than the market for purchases of required inputs. Spot transactions are extremely short-term transactions where prices are determined by short-run supply and demand. Spot transactions provide flexibility to the buyer in balancing supply with demand. Long-term contracting represents what can be viewed as an “in-between” transaction, where the seller and buyer rely on the market, but they desire more certainty in price and other attributes of a trading arrangement than contained in a spot-market transaction. (Spot markets also require repeated trading, which over time can drive up transaction costs, discussed below.) Contracting has several dimensions that are negotiated between the buyer and seller, with the outcome largely dependent on market conditions, which include predictability of the future and the relative bargaining strength of each party.</p>
<p>What we have found across a wide spectrum of industries is that long-term contracting becomes the predominant form of governance for large investments with limited alternative use. Under this specific condition, long-term contracts may be needed to protect the financial interest of investors by mitigating intolerable risk.</p>
<p>As an illustration, let us assume that a factory’s production line is designed to produce customized widgets for a single customer. The factory manager likely would require a long-term contract with provisions that protects the factory’s financial interest in the event that the customer decides either not to buy at all or only continues buying if a low price is offered. The economic reason for a long-term contract lies with the factory expending large sums of dollars to design its production line to provide the kinds of widgets that the customer desires. Such relationship-specific investments usually require contracts of a long duration. Both economic theory and real-world observations support this trade governance.</p>
<p>Another way of describing this, in the arcane jargon of economists, is that the condition of imminent opportunistic behavior in the presence of expensive specialized assets is highly conducive to long-term contracting or, under extreme conditions, vertical integration. The absence of long-term contracting can then lead to under-investments. These are the basic arguments being advanced by pipelines in lamenting the erosion of long-term contracts in recent years.</p>
<p>Economic theory supports the idea that transaction costs are crucial for shaping the institutional arrangements for the exchange of goods and services. According to transaction cost theory, which category of trading arrangement (spot, longer-term contracting, vertical integration) is consummated depends on the attributes of a transaction. For example, when asset specificity, sunk costs, and a high degree of complexity characterize the trading environment, vertical integration may be most economical. (This would be especially true with the presence of high transaction costs from coordinating, synchronizing, and harmonizing different complicated processes through market arrangements.)</p>
<p>In the case of contracts, transaction costs originate from:</p>
<p>(1) search and information acquisition;</p>
<p>(2) initial negotiation;</p>
<p>(3) monitoring;</p>
<p>(4) enforcement;</p>
<p>(5) haggling at contract renewal; and</p>
<p>(6) deviation of evolving market conditions from contract terms and conditions.</p>
<p>When these costs are high relative to the transaction costs of spot transactions and vertical integration, contracting becomes untenable. In terms of the optimal duration of a contract, two opposing forces come into play. The first, favoring longer-term contracts, pertains to the cost of negotiating terms of trade on a period-by-period basis (for example, annually, or even more frequently as in the case of a spot transaction), which other things held constant, would drive up transaction costs over time. The second, causing longer-term contracts to be less attractive, relates to the risk of being constrained under an inflexible arrangement over a longer period of time. The main problem here is that this rigidity could be highly costly in an uncertain market environment and could lead to the shipper being stuck with overpriced gas to sell.</p>
<h4>The Context: The Current Gas Pipeline Sector</h4>
<p>Long-term contracting is a legacy of the pre-1980s natural gas industry. Contracts were generally for 20 to 30 years, at fixed prices, for both producer-pipeline transactions (take-or-pay contracts) and pipeline-local gas utility transactions (minimum-bill service agreements). The unraveling of long-term contracting, especially with rigid terms and conditions, coincided with the restructuring of the natural gas industry in the early 1980s, with wellhead price liberalization and major FERC actions opening up wholesale gas markets. In fact, a major impetus for restructuring of the natural gas industry was the high social cost associated with rigid long-term contractual arrangements that became more evident as the industry transitioned to a more liberalized structure.</p>
<p>With the natural-gas sector restructuring from a highly regulated industry to a much more market-oriented one, trading arrangements have become much more short term and flexible in both price and in terms and conditions. We have observed this phenomenon throughout the natural-gas sector, from gas procurement, gas storage, and retail transactions, to capacity contracting for pipeline services.</p>
<p>The primary force behind this broad reshaping of trading arrangements lies with simple economics. For example, retail consumers now have more choices of suppliers and gas utilities face more uncertainty over future prices and their load requirements. As gas utilities downsize the bundled-sales-service side of their business, they will invariably have less demand for long-term pipeline capacity. Overall, competitive pressures have made long-term commitments a more expensive proposition for gas utilities as well as other shippers by increasing risk.</p>
<p>The pronounced trend away from long-term contracting during the past 20 years is the result of the natural-gas industry becoming more open and competitive. The shifting of trade toward shorter-term arrangements, for both gas supplies and transportation, is compatible with the dramatic change in the market environment that has occurred over this period of time. In line with transaction-cost economics, these changes have lowered the relative transaction costs of shorter-term trading arrangements. In other words, the market participants are acting rationally in preferring shorter-term transactions as the natural-gas market environment has evolved.</p>
<p>Although many shippers, especially local gas utilities, generally prefer multi-year contracts for firm gas transportation, they also have opted for shorter-term and more flexible arrangements. These transactions make it easier for a shipper to vary its take in adapting to changed conditions in the absence of irreversible commitments. The evolution of market centers and hubs has expanded the market services by providing shippers with greater gas supply and transportation choices.</p>
<p>Price basis differentials (for example, the difference between gas prices at two market hubs located in different regions) and perceived demand are the driving forces for pipeline capacity expansion. In the past several years, most local gas utilities have procured a portfolio of pipeline arrangements. Many non-utility shippers, such as marketers and large gas consumers, have preferred shorter-term arrangements strictly for economic reasons. (For example, electric generators selling power without long-term commitments from its buyers would be hard pressed to economically justify signing a long-term contract with a pipeline.) Overall, emphasis has shifted toward shorter-term transactions and flexible arrangements with regard to the amount of pipeline capacity reserved, as well as the duration of contracts.</p>
<h4>Trying to Make Sense of This</h4>
<p>The evolution of the natural-gas market has made long-term contracting for pipeline services less attractive for shippers, whether local gas utilities, marketers, or large gas consumers. Shorter-term transactions have become the economically preferred arrangement for transacting gas pipeline services in addition to transactions for the gas itself and other industry services that have become more competitive over time. Local gas utilities see the risks associated with long-term contracts with inflexible terms and conditions, particularly when they endure beyond their planning horizons, which have shortened in recent years.</p>
<p>As they often do, local gas utilities have long-term contracts with pipelines, but they generally prefer a portfolio of pipeline arrangements that gives them more flexibility in adapting to changing market conditions. In FERC <em>Docket No. RM98-10-011</em>, when discussing the matching-term cap under the right-of-first-refusal mechanism, the American Gas Association (AGA) argues that long-term (beyond 5 years) agreements with pipelines “may expose the [gas utility] and, ultimately, the end-use consumer, to investments for capacity commitments beyond needs specifically identified simply because a lengthier contract term would be required in order to secure supply in the short term.” AGA goes on to say that a “lengthy contract” could force a gas utility to “bear all the risk associated with that contract, including the underlying financial obligation, regardless of future events that might lessen its capacity requirements.”</p>
<p>Events in the natural gas industry over the last several years have made new pipeline capacity less of a relationship-specific investment (which, as discussed above, is the primary condition for long-term contracting). This is partially a result of increased competition in the wholesale gas market induced by the creation of market centers/hubs and the secondary capacity-release market. For example, since FERC Order No. 636, the gas pipeline network has become substantially more interconnected between spatially distinct markets (meaning individual pipelines have enlarged markets), with competition consequently improved. The effect of the increased density of producers and pipelines over the last several years has attenuated the specificity of production and pipeline capacity, with the effect of a reduced need for long-term contracts to support investments in pipeline capacity. This development also has increased shippers’ ability to bypass and thereby reduced their preferences for long-term price protection. Simply put, with a more open market that has evolved in the natural-gas industry, long-term transactions have less economic appeal to shippers.</p>
<p>Notwithstanding these developments, which seem highly sensible and reflective of a well-functioning gas market, the pipelines may actually have a legitimate gripe that longer-term contracting may be underused because of the policies of FERC and state commissions. This argument stems from the possibility of market and regulatory distortions leading to a non-optimal mix of trading arrangements. Specifically, this refers to: (1) regulatory uncertainty at the state level over the prudence of long-term contracts (which local gas utilities fear easily could lead to regulatory opportunism and a potential stranded-cost problem); (2) the design of some gas choice programs that allow customers to switch suppliers on short notice and consequently make it difficult for a gas utility to contract on a long-term basis for default customers; (3) the unwillingness of some state commissions to hold retail marketers to the same standard of reliable service as the default gas utility; and (4) FERC’s pricing policies, which, as some industry observers have argued, may induce excessive demand for short-term transactions (which include interruptible service and capacity-release transportation) in relation to longer-term transactions.</p>
<p>All or some of these, arguably, could have artificially shifted preferences by shippers toward shorter-term contractual arrangements with pipelines. As an example, pipeline rates for short-term service may be too low relative to rates for long-term service. Regulatory uncertainty at the state level may discourage local gas utilities from signing long-term contracts that could, with hindsight, turn out to be inefficient and burdensome on retail customers. But this argument overlooks how state regulators place such high priority on gas utilities having highly reliable service—which most regulators believe requires some long-term contracts in a utility’s portfolio mix.</p>
<h4>Policy Implications for Regulators</h4>
<p>Local gas utilities should have the discretion to sign long-term contracts for pipeline transactions. State commissions should approve these transactions as long as they can appropriately fit in a utility’s gas portfolio or supply strategy. Commissions may want to consider granting upfront approval of long-term contracts and their costs within the context of a strategy proposed by a utility.</p>
<p>Giving preapproval may alleviate a utility’s doubts over whether the costs associated with long-term contracts ultimately will be recovered. To say it differently, preapproval could overcome a potential stranded-cost problem for gas utilities providing default service. Of course, on the other hand, preapproval of costs shifts risks onto retail customers.</p>
<p>A less extreme measure could have a commission establish guidelines that would reduce uncertainty for a gas utility. Guidelines, or <em>ex ante</em> rules, can include a commission’s general position on long-term contracting, cost-recovery criteria articulating what constitutes reasonable actions by a gas utility, and the scope of a hindsight review (which would depend on the degree of commission commitment upfront to long-term contracting). In evaluating a gas procurement/supply strategy that contains long-term contracting, a commission should consider the risk on a utility and its bundled-sales-service customers.</p>
<p>State commissions should take a neutral position on long-term contracting and should support long-term trading arrangements when they are an integral part of a utility’s optimal gas procurement/gas supply portfolio. While long-term contracting may have a useful function, it should not be a requirement for local gas utilities and other shippers. These purchasers of gas and transportation are under increased pressure to achieve a targeted level of reliability at the least cost, which may involve relying little, if at all, on long-term contracting for pipeline services.</p>
<p>At the federal level, FERC should consider giving pipelines more pricing flexibility in marketing their capacity. This would enhance the pipelines’ opportunities to market their unsubscribed capacity.</p>
<p>While FERC allows a limited degree of pricing flexibility with regard to short-term transactions and released pipeline capacity, less flexibility is allowed for long-term contractual arrangements, where rates largely are determined by rigid cost-of-service criteria. (In FERC <em>Order No. 637</em>, however, pipelines were encouraged to offer shippers lower rates for longer-term contracts—what FERC calls term-differentiated rates; so far, pipelines have not been active in proposing such rates, which could provide a stimulus for long-term contracting.) FERC has recognized that departure from the typical straight-fixed variable rate design may occasionally be necessary to make under-subscribed capacity more marketable. This can help to soften the revenue risks associated with short-term transactions. FERC also can consider reducing a pipeline’s depreciation period to, for example, better match capital recovery with actual contract durations. Such ratemaking changes, which have been proposed by pipelines, can help compensate a pipeline for absorbing higher risk because of market developments.</p>
<p>An important empirical question, and one that has yet to be answered in addressing the pipelines’ argument, relates to the extent to which the evolution of shorter-term transactions has hampered investments in new pipeline capacity. As FERC has reported, new pipeline capacity is being built in all parts of the country (especially in the Rocky Mountain region, where the economics are most attractive), with no apparent evidence of expected capacity shortfalls, except perhaps in isolated locales. The latest long-term energy forecasts by the Energy Information Administration<sup>2</sup> identified public opposition to the building of pipeline capacity as a potential problem that could lead to higher natural gas prices; it made no mention, however, of the deficiency of long-term contracts as an impediment to pipeline expansion. Skeptics of long-term contracting have argued that other industries making large investments under competitive conditions do so without any prior guarantees of capacity utilization.</p>
<p>The changing market environment, rather than state or federal regulatory actions, better explains the radical shift toward shorter-term transactions since the mid-1980s. The natural gas market seems to be responding rationally and efficiently in adapting to the more open and competitive environment. We should expect to see more interest in long-term contracting in the future if and when the price for short-term transactions starts to rise because of scarcity in regional pipeline capacity. But other than this development, the lower preference for long-term contracting by shippers is compatible with their self-interest. More important, shorter-term transactions have fostered a more efficient and socially desirable natural-gas industry.</p>
<p>Advocates of long-term contracting have not made a case for their position, which comes across more as self-serving than anything else.</p>
<p> </p>
<h4>Endnotes:</h4>
<p>1. As defined here, although other market observers may disagree, long-term contracts have time durations of 5 years or more.</p>
<p>2. EIA’s <em>Annual Energy Outlook 2005</em>.</p>
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Fri, 01 Jul 2005 04:00:00 +0000puradmin10905 at http://www.fortnightly.comPower Measurementhttp://www.fortnightly.com/fortnightly/2004/06/power-measurement
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>A look at issues that could keep energy executives up at night.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Gary L. Hunt and Jon Ecker</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - June 2004</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><blockquote><h1 class="dept">Power Measurement</h1>
<h3>A look at issues that could keep energy executives up at night.</h3>
</p>
<p>The most common strategic issue depriving utility executives of sleep is the looming clash of investor expectations for steady growth in earnings compared with what utilities can deliver given slow growth in customers and demand. While many dream of assured regulated rates of return, the reality for most utilities is that the 1.5 percent retail growth experienced between 2002 and 2003 will prove unsatisfactory for earnings. Wall Street expects 10 percent growth. Even with improving gross domestic product, the best organic growth we will see is around 3 percent, leaving a gap of 7 percent.</p>
<h3>Bridging the Gap</h3>
<ul>
<li><b>Ratebase Additions.</b> On average, ratebase growth was slightly more than 5 percent in 2003. While this makes up a significant portion of the growth gap, it still leaves the industry a few percentage points short of the 10 percent target. Utilities looking to add to the ratebase by buying generation at attractive prices have found it difficult to get their state PUCs to allow them to put it into the ratebase unless they go through a competitive procurement process that demonstrates the prudence of the decision. Additionally, utilities that try to acquire assets through an unregulated affiliate face extensive regulatory attention over the affiliated transaction and whether it is sufficiently arms-length to be prudently recovered in rates.</li>
<li><b>Rate-of-Return Hits.</b> Utilities seeking rate increases run significant risk that regulators will respond by cutting allowed rates of return given low interest rates, lower cost of capital, lower perceived risk, and low capital investment.</li>
</ul>
<p>Working off the excess in new generation supply brought on line in the last few years has resulted in very high reserve margins and commensurate low profitability for natural gas-fired generation across many (but not all) markets. These high reserve margins are a significant turnaround from the situation that existed in the late 1990s. Figure 1 shows cumulative load growth and cumulative generation additions since 1990 in North America. Cumulative generation additions fell behind cumulative load growth during the decade of the 1990s.</p>
<p>Illustrated another way, Figure 2 compares the chronology of new capacity additions by fuel since 1950. The figure is notable for two reasons. First, it compares the staggering level of building during the recent building boom to pervious years and, second, it shows that industry has relied almost exclusively on natural gas capacity to meet incremental load growth for the coming years. With this, the path toward fuel diversity for power generation has swerved. It remains to be seen how this development will play out in the market and whether increasing the reliance on natural gas fuel will have long lasting implications for other sectors of the economy.</p>
<h3>Acquisitions</h3>
<p>Consolidation in the energy industry is coming. Pressure to grow earnings likely will result in some consolidation in the utility and other sectors of the energy industry as investors seeking higher returns and share prices will be affected by the market perception of the growth potential of the stock.</p>
<p>"Back to basics" is not likely to last long as a strategy. The boom-and-bust cycle is alive and well. Every expansion period-like the merchant boom we have experienced-is followed by a period of contraction, consolidation, and rationalizing. The process of consolidation and rationalization is just beginning, and some players will not survive the experience.</p>
<p>The purchases of MidAmerican Energy by Warren Buffett and of DPL by KKR are only two examples of the potential for new players to enter the market with innovative or disruptive business strategies in an effort to capture advantage.</p>
<p>Investor-owned utilities see significant buying opportunity from among the merchant assets built during the boom. The Federal Energy Regulatory Commission (FERC) considers the utility purchase of a merchant power plant a threat to wholesale competition going forward. State utility commissions perceive such purchases as undermining the arms-length nature of the competitive power markets in ensuring that customers get the least-cost, most reliable energy supply to ensure resource adequacy. For the investor-owned utility this often represents a catch-22. While it makes no sense to build new generation in an overbuilt market, regulators at both FERC and state levels are prepared to restrict or punish the utility for such an initiative. The back-to-basics strategy further exacerbates this problem. Power contracts are not included in the ratebase calculation; thus, the utility is further incented to build new assets in overbuilt markets in an attempt to drive 10 percent growth. For municipal and cooperative utilities, the fear of getting involved with potentially uncreditworthy merchant generators or projects means they, too, are building to meet their resource needs in an era of substantial oversupply.</p>
<p>After the trashing of SMD, will FERC use its regulatory review authority to bring intense pressure on the holdouts? Remember what FERC did to the holdouts on Order No. 636? Some firms that resisted FERC found themselves starving or strangled by regulatory delay or disapproval, and some did not survive the experience.</p>
<h3>The Ticking Time Bomb of Merchant Financial Structuring</h3>
<p>Excess generating capacity and weak demand is slowing recovery in the merchant energy sector. Energy Velocity data shows there has been a significant decline in the average capacity factor over the past 10 to 15 years. Many merchant projects built since 2000 were expected to run as base-load units, replacing older, less efficient units. The average capacity factor of the 900-plus units built since 2000 is less than 25 percent, and the lion's share of units dispatching as base load came online between 1955 and 1991. The overbuild and low capacity factors mean that mini-perm refinancing just completed by many merchant plant owners may not last long enough to get through the crisis to equilibrium. Purchase power agreements (PPAs) are being imputed as debt on balance sheets, setting up an argument for high returns on equity in rate cases at FERC, but the rating agencies seem to be treating PPAs like debt.</p>
<p>Private equity firms are making investments in merchant generation that are not subject to the Public Utility Holding Company Act. KKR's proposed purchase of UniSource and Texas Pacific Group's proposed purchase of Portland General Electric are two examples. Will these private equity companies accelerate the M&amp;A potential of the industry by using these acquisitions as cash cows for other purchases while using allowed rates of return of regulated utilities to smooth their overall portfolio returns?</p>
<p>Although much progress has been made in cleaning up the liquidity issues facing the merchant generators, those "fixes" may not be sufficient to carry the merchants through the process of working off the excess. The back-to-basics strategy and the resulting earnings gap will push utility executives to look externally for the quick fix-acquisitions. Those who choose the more challenging path will need to convince their PUCs to let them take advantage of distressed assets or allow power contracts into the ratebase if they expect to beat The Street. If low earnings growth, high reserve margins, and commensurate low profitability aren't causing insomnia already, the new back-to-basics strategy just might.</p>
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Tue, 01 Jun 2004 04:00:00 +0000puradmin11043 at http://www.fortnightly.comPerspectivehttp://www.fortnightly.com/fortnightly/2002/04-0/perspective
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>The industry has moved beyond the debate.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Michel Marcoux is a partner in Bruder, Gentile &amp; Marcoux, L.L.P., a Washington, D.C., law firm engaged in natural gas and electric utility industry work. He can be reached at (202) 783-1350. Web site: <a href="http://www.brudergentile.com">www.brudergentile.com</a>.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - April 15 2002</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><blockquote><p>
<div align="center"> By </div>
<h3 align="left">The industry has moved beyond the debate. </h3>
<p align="left"><b>Ron Hrehor's and Don Sytsma's Feb. 15, 2002 vision in this magazine</b> ("Gas Power Infrastructure: The Missing Link?", p. 32) of natural gas industry potential to address electric industry problems, notes in passing that interstate pipelines are advancing more flexible services for generators, including services that now offer firm hourly transportation.<sup>1</sup> But, there is more to that story. Putting flesh on the gas-power vision, pipeline efforts to formulate services for generators, and FERC orders governing those efforts now assume a discernible shape. This is a reasonable time to take stock. </p>
<h3 align="left">A Fuel with Electrifying Prospects </h3>
<p align="left">The ongoing Enron scandal and the 2000-2001 California electricity crisis are causing financing and regulatory uncertainty today for gas-fueled generation and other energy markets.<sup>2</sup></p>
<p align="left">Despite those phenomena, the Energy Information Administration (EIA) predicts that the less capital-intensive and more efficient generation of electricity from gas, including cogeneration, will double from 16 percent in 2000 (52 percent coal, 20 percent nuclear, 9 percent renewable) to a projected 32 percent in 2020 (46 percent coal, 13 percent nuclear, 8 percent renewable).<sup>3</sup> EIA also projects 355 gW of new electricity generating capability, excluding cogeneration, consisting of 88 percent gas, in combined-cycle or combustion turbines and distributed peak generation, over the same 20 year period.<sup>4</sup> Electric issues of generator interconnection, transmission and regional transmission organization (RTO) formation-structure-governance will be influenced, and likely heavily so, by locating, sizing, pricing, and operating via gas fuel that 88 percent of new electricity generating capability. Where such electric issues are subject to competing federal/state interests, only FERC regulates interstate delivery of gas. </p>
<p align="left">In the near term, FERC's Order No. 637 anticipates greater integration of gas transportation and electric generation markets, with gas usage for power generation expected to grow substantially.<sup>5</sup> Order No. 637 fosters that integration by: (1) insisting on capacity segmentation to increase value and on better management of capacity imbalances; (2) minimizing pipeline operational flow orders and providing for penalties to customers only where operational reliability is impaired; (3) promoting new approaches to capacity pricing through term-differentiated (lower rates for longer terms) and peak/off-peak rates; and (4) experimenting with capacity releases of less than a year. </p>
<h3 align="left">New Services that Work for Generation </h3>
<p align="left">Hrehor and Sytsma see pipeline system physical assets, and pipeline regulatory, commercial and operational aspects, as helping to develop new generation in power-constrained locations.<sup>6</sup> In the past two years, pipelines have put in place transportation services to attract the business of electric generators, using available pipeline capacity not already subscribed. </p>
<p align="left">On the Texas Gas Transmission Corporation system,<sup>7</sup> the pipeline demonstrates sufficient unsubscribed capacity and other available capacity from turnbacks by existing customers to support a new electric generation service with pipeline and off-peak storage capacity. FERC praises Texas Gas's resolution of competition for capacity at particular points by evaluating bids on a highest net present value basis, awarding capacity to those valuing it most highly. For ANR Pipeline Company, FERC approves firm (FT) and interruptible (IT) transportation services customized for electric generation that will not degrade firm primary capacity rights.<sup>8</sup></p>
<p align="left">Other new services target summer capacity. Orders for Gulf South Pipeline Company<sup>9</sup> approve the use of unsubscribed no-notice service (NNS) as a summer option for electric generation. In 1992, pipeline acknowledgements that NNS in fact could be done (replacing the FT component of bundled firm sales with stand-alone, enhanced firm service without daily penalty) helped make open access policy acceptable to FERC.<sup>10</sup> However, NNS's star may no longer be in the ascendant. Even were Gulf South NNS customers to take all their maximum daily quantities (MDQ) during any hour-a scenario the pipeline views as never contemplated, physically impossible, and degrading to other firm services-FERC concludes Gulf South unsubscribed NNS capacity is sufficient to support the new electric generation service. FERC also approves a Natural Gas Pipeline Company of America (Natural) counter-cyclical service to meet summer generation load with off-peak no-notice storage.<sup>11</sup> With storage and transportation separately releasable, the pipeline manages storage and cushion gas to provide daily reversed storage (summer withdrawals, winter injections) and reserves capacity for existing firm commitments. FERC finds no reason to believe the pipeline would act imprudently, such as by overselling a delivery zone. </p>
<h3 align="left">Ascertaining Existing Customer Capacity Limits </h3>
<p align="left">Aware that pipelines historically are designed to supply gas to customers (primarily residential) at constant rates of flow, Hrehor and Sytsma propose a "joining" of gas and electric markets to achieve lowest delivered energy costs to both gas and power consumers through a consistent "regulatory framework and jurisdiction", i.e., "proceedings at FERC."<sup>12</sup> In orders for Panhandle Eastern Pipeline Company,<sup>13</sup> FERC emphasizes that FT for electric generation may complement other firm service capacity use, rejecting as speculative existing customer concern that their services will be degraded. The pipeline allocates no specific capacity to the electric generation FT, and FERC accepts its assurance of case-by-case evaluation to avoid adverse impact on other firm users. In the Gulf South orders, relying on earlier analysis for Transwestern Pipeline Company,<sup>14</sup> FERC finds rights of existing capacity holders are not diminished unduly by offering available, unsubscribed capacity to generators. Such existing holders, FERC explains, have no right to expect unsubscribed capacity to be maintained in order to minimize the possible effects of a curtailment. With no specific capacity allocated to new summer service, and accepting Gulf South's assurances that each request for service will be evaluated for unsubscribed capacity available, FERC finds no effect on the pipeline's ability to make all firm deliveries (however, summer IT capacity may be limited). FERC's orders for Natural declare that existing customers cannot claim the system's entire capacity, above their contract limits. Such claims would restrict the pipeline's ability to grow efficiently, confining the addition of new customers to a proposed sharing of the cost of service, if and when new rate cases are filed. </p>
<p align="left">There are limits to the favor electric generation enjoys. In Colorado Interstate Gas Company orders,<sup>15</sup> FERC states that pipelines must improve their flexibility to serve electric generation load, while also protecting existing firm shippers' services. FERC says operational constraints may be necessary to protect those incumbent services. Also, in another series of ANR orders,<sup>16</sup> FERC concludes the pipeline cannot resell other subscribed, but unnominated and unscheduled, firm capacity to implement a limited firm service to an electric generator. FERC says a new, limited FT service must not degrade existing firm services, and refuses to allow the pipeline to collect double reservation charges for the same capacity. Finally, Tennessee Gas Pipeline Company proposed a new electric generation service, stating that current daily transportation quantities of existing services carry the general expectation that those shippers receive scheduled volumes at uniform hourly flow over the gas day.<sup>17</sup> Over protests that such an expectation threatens existing customer FT flexibility at hourly-equivalent levels above MDQ, the pipeline withdrew its generation service tariffs. </p>
<h3 align="left">Efficient Service to Burgeoning Electric Generation Loads </h3>
<p align="left">Hrehor and Sytsma point to the "frequent and fairly rapid changes in gas flow" required by generators, and comment that gas and electric markets often are geographically identical, and conclude power customers might use the gas pipeline infrastructure to "enable the strategic placement of new generation" to reduce transmission constraints.<sup>18</sup> While responsive to the operational requirements of the particular systems, several new pipeline services enable generators to react more promptly to spiking electric demand. The new Panhandle Eastern service accommodates generators through daily FT with the enhanced flexibility of accelerated flow rates for shorter time periods on shorter notice. Shippers notify the pipeline three hours before delivery and may take, within certain time periods, up to their MDQ in designated hourly increments from one to 16 hours. Nominated and scheduled daily, the service is balanced monthly. Only connected electronic flow measurement points are served, with the service restricted to one shipper contract at a delivery point, since multiple contract flows are not distinguished. Other orders, for Reliant Energy Gas Transmission Company,<sup>19</sup> approve shipper nominations at any time, effective at the start of the hour if made 60 minutes earlier. The pipeline posts scheduled quantities on the Internet prior to gas flow as an Order No. 637 tool for customers to manage imbalances and avoid penalties. Gas Industry Standards Board (GISB) restrictions on FT bumping of IT are waived to implement hourly firm nominations, except IT shippers are not bumped either after 5 p.m. on gas flow day or if bumping outside GISB grid-wide synchronization times affects transactions on other pipelines. ANR provides another fast service, with variable hourly flow rights enabling the customer to swing the entire daily entitlement in as few as four hours. The service commences and shuts down on short notice, flexibly allowing users to manage their receipt and delivery variances. </p>
<p align="left">CIG service for hourly entitlement enhancement nominations flexibly provides defined hourly transportation rights. By meeting operational requirements (such as the gas passing two or more specified compressors) shippers can alter hourly flows for hourly demand swings. Hourly flow is increased from 1/24 to 1/18 of daily entitlement, limited daily to MDQ. Finally, for Texas Gas's generator service, shippers nominate quantities for FT through available capacity, just like existing FT. The pipeline combines that nomination with available off-peak storage capacity to handle delivery swings on an unnominated, firm NNS basis, April through October. There is variable hourly flow at primary delivery points and provision for seasonal, daily and hourly overruns, with other features mirroring existing NNS. </p>
<h3 align="left">Propitious Present Moment </h3>
<p align="left">Potential customers from the electric industry face a receptive interstate pipeline industry on issues of employing the grid to ship natural gas to generate power. FERC largely approves gas transportation services for electric generation that pipelines propose, using their systems' available capacity not already subscribed. Those new services likely will play a very important role in resolving today's electric industry problems such as generator interconnection, transmission and RTO matters. </p>
<p align="left"></p>
<ol>
<li> R. Hrehor &amp; D. Sytsma, 140 Public Utilities Fortnightly 32, 35. </li>
<li> See FERC Feb. 13, 2002, Docket No. PA02-2-000, Fact-Finding Investigation of Potential Manipulation of Electric and Natural Gas Prices [in the West], Order Directing Staff Investigation. </li>
<li> Annual Energy Outlook 2002, EIA, U.S. DOE publication DOE/EIA-0383 (Dec. 2001) at 137. </li>
<li> ., 138. </li>
<li> FERC Stat. &amp; Reg. ¶31,091, 31,250 (2000). </li>
<li> Hrehor &amp; Sytsma, , 32. </li>
<li> 90 FERC ¶61,016, 91 FERC ¶61,200, 93 FERC ¶61,113 (2000). </li>
<li> 89 FERC ¶61,210 (1999); 90 FERC ¶61,213, ¶61,339 (2000). </li>
<li> 92 FERC ¶61,164 (2000); 95 FERC ¶61,086 (2001)(formerly Koch Gateway). </li>
<li> Order No. 636, FERC Stat. &amp; Reg. ¶30,939 at 30,408 &amp; n.100, 30,422 &amp; n.131; 18 C.F.R. §284.7 (a)(4). </li>
<li> 90 FERC ¶61,182, 92 FERC ¶61,221 (2000); 94 FERC ¶61,242 (2001). </li>
<li> Hrehor &amp; Sytsma, , 34-35. </li>
<li> 90 FERC ¶61,119, 91 FERC ¶61,174, 93 FERC ¶61,611 (2000); 94 FERC ¶61,209, 95 FERC ¶61,211 (2001). </li>
<li> 90 FERC ¶61,044 (2000). </li>
<li> 95 FERC ¶61,099, ¶61,486, 96 FERC ¶61,330, 97 FERC ¶61,208 (2001). </li>
<li> 97 FERC ¶61,096 (2001); 98 FERC ¶61,067 (2002). </li>
<li> 93 FERC ¶61,243 (2000); 94 FERC ¶61,365 (2001). </li>
<li> Hrehor &amp; Sytsma, , 35-37. </li>
<li> 93 FERC ¶61,141 (2000); 94 FERC ¶61,322 (2001). </li>
</ol>
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Mon, 15 Apr 2002 04:00:00 +0000puradmin11415 at http://www.fortnightly.comGas-on-Gas Discounting: Still a Zero-Sum Gamehttp://www.fortnightly.com/fortnightly/2000/04-0/gas-gas-discounting-still-zero-sum-game
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>The Policy: Blind Faith in Supply-Side Subsidy</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>J. Michel Marcoux</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - April 15 2000</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><blockquote><h1 align="center">Gas-on-Gas Discounting: Still a Zero-Sum Game</h1>
<div align="center">
<p></p>
</div>
<div align="center">
<p></p>
</div>
<p align="center"><b>Captive shippers still face rate hikes without reward under the FERC's new rule on short-term pipeline capacity.</b> </p>
<p align="left"><b>In its final rule issued on short-term gas pipeline capacity,</b> announced Feb. 9 in Order No. 637,[Fn.1] the Federal Energy Regulatory Commission squanders a precious opportunity to end a discrimination inherent in its pipeline rate discounting policy.</p>
<p align="left">In practice, that policy permits interstate pipelines to raise rates for captive customers to offset discounts they give to other customers that enjoy access to competing interstate pipelines. The theory behind this privilege is simple. The pipelines justify their discounts on the claim that all customers, including non-favored customers that get no discounts or lesser discounts, will benefit. How? The benefit, it is said, comes from an increase in units of service provided - a result of the discounting. </p>
<p align="left">Alas, that common theory rests on a mistaken assumption. Not one more dekatherm flows in the interstate pipeline grid because of this pipeline-on-pipeline (or "gas-on-gas") discounting. Instead, one pipeline's increased units of service merely other pipeline loads; their combined units of service do not increase. Furthermore, the FERC's answer of adjusting ratemaking throughput[Fn.2] to recoup such discounts discriminates against non-favored customers because their higher rates subsidize discounts to the favored customers. The extra units of gas are not real. The gas-on-gas discounting emperor has no clothes. </p>
<p align="left">The FERC's 1998 Notice of Inquiry,[Fn.3] heralding the Final Rule, asked two questions relevant to this issue. First: Do these discount-related rate adjustments unfairly affect captive customers (those whose short-term demands do not vary with price)? Second: What constitutes a reasonable limit on the extent to which pipelines can recover the costs of their discounts? For gas-on-gas discounting, fairness dictates two straight-forward answers: (1) "yes," and (2) "no rate adjustments are reasonable." Yet the Final Rule leaves those questions dangling, noting only that the FERC is "still considering ... whether to permit discount adjustments."[Fn.4] </p>
<p align="left">While the Final Rule takes a pass, gas-on-gas rate prejudice against captive customers endures. The Final Rule's standard gas-on-gas regulatory model remains open to challenge, whether at the FERC by complaint as "pernicious,"[Fn.5] in pipeline rate case hearings, or in a later court appeal. Instead of waiting for such a challenge, the FERC should repair the gas-on-gas standard model. </p>
<h3 align="left"> The Policy: Blind Faith in Supply-Side Subsidy</h3>
<p align="left">Since opening access to the interstate grid in 1985, the FERC has allowed pipelines to discount their transportation services at will and then to regain those discounted dollars by commensurate adjustments lowering the volume of throughput that is entered in the ratemaking formula, thus raising rates. The FERC argues such subsidized discounting (by customers not awarded the discounts), including subsidized gas-on-gas discounts, benefits all customers by allowing a pipeline to maximize actual physical throughput, thus spreading fixed costs over "more units of service."[Fn.6] </p>
<p align="left">The Final Rule acknowledges that pipelines exercise market power through such selective discounting at rates below the FERC-set maximum rate ("in effect price discriminating").[Fn.7] Nevertheless, the Final Rule then sets out the standard, broad-brush rationale that increased units of service, leading to higher annual revenues for pipelines, will benefit the captive customers paying maximum cost-of-service rates. According to this rationale, the increased service reduces, in the pipeline's next rate case, costs that otherwise would be recovered through rates paid by those captive customers.[Fn.8] Nowhere does the Final Rule recognize that pipelines actually reduce the level of throughput reflected in the ratemaking process to force non-favored customers to subsidize discounts. </p>
<p align="left">Moreover, it overlooks an obvious problem: Discounting only furthers what is essentially a zero-sum game. </p>
<p align="left">Gas-on-gas competition often takes the form of a pipeline's competing with another interstate pipeline for a customer. Favored customers with access to both pipelines - but not those customers captive to only one pipeline - get the discounts. Another typical form of gas-on-gas competition occurs among the users of a pipeline's own rate schedules for transportation service, including capacity release. When firm contracts expire, pipelines grant demand charge discounts to compete with their own interruptible transportation rates, which also often are discounted. </p>
<p align="left">A pipeline's rates increase in step with its discounting to meet such gas-on-gas competition from other interstate pipelines or with itself.[Fn.9] Gas-on-gas discounting amounts to substantial dollars across the grid.[Fn.10] Furthermore, gas-on-gas, pipeline-on-pipeline, discounting (and related ratemaking throughput adjustment) by definition impacts more than one pipeline's customers. Yet after the deals are struck, not one additional dekatherm moves across the FERC-regulated pipeline grid. </p>
<p align="left">Discounting to meet gas-on-gas competition fails to spread fixed-cost recovery over more units of service. Markets a pipeline wins in gas-on-gas competition with another pipeline, or among the pipeline's own rate schedules, merely displace units of service otherwise delivered by that other pipeline, or under another rate schedule. No real increase in economic output occurs. </p>
<h3 align="left"> The Rebuttal: A Case Ripe for Judicial Review</h3>
<p align="left">Not all discounts are bad; nor do they all discriminate. Some discounts aim to meet competition from alternate fuels or from pipelines not regulated by the FERC. These discounts may well increase units of service across the interstate grid, to the benefit of non-favored customers as well as customers getting discounts, which the gas-on-gas discount does not do. The question for this discussion, however, is whether the appellate courts recognize this distinction between load-building and zero-sum discounts and, if so, how might they rule on the FERC's current policy? </p>
<p align="left">In the 1980s, in a slightly different context involving pipeline discounts of gas , not transportation, the U.S. Court of Appeals for the D.C. Circuit had occasion to test the FERC's policy to see if such discounts made a contribution to fixed costs that otherwise would not be made at all. When the court found that equitable justification to be "missing," it said "no" to the policy in question.[Fn.11] </p>
<p align="left">In fact, on at least three separate occasions since then, the D.C. Circuit Court has insisted that the issue of pipelines adjusting their rates to offset discounts to meet gas-on-gas competition has not even been addressed, let alone analyzed or approved: </p>
<ul>
<li>
<div align="left"><b>Deferring the Issue.</b> In 1987 the court explained that issues of rate differentials based exclusively on competition between transporters with similar cost functions [i.e., interstate pipelines] may "properly" be deferred to another day and another proceeding for ultimate resolution.[Fn.12] </div>
</li>
<li><b>Withholding Any Opinion.</b> The D.C. Circuit Court in 1995 ruled that the court has not specifically addressed the "legality of gas-on-gas discounts."[Fn.13] </li>
<li><b>Emphasizing the open question.</b> The court in 1996 defined standard model FERC selective discounting to include that 1995 ruling that the legality of gas-on-gas discounts has not been specifically addressed (on review of Order No. 636 unbundling of sales and transportation services).[Fn.14] </li>
</ul>
<p><center><br />
<p align="left">Even general rate design principles leave the gas-on-gas problem open to challenge. Correcting the problem would be required under the anti-discrimination discounting objectives of the FERC's 1989 Rate Design Policy Statement: (1) to maximize throughput, and (2) to "prevent subsidization of the discounts by the pipeline's nondiscounted rates."[Fn.15] </p>
<p align="left">Disallowing ratemaking adjustments for gas-on-gas discounts actually promotes the second objective, by removing captive customer subsidies of discounts a pipeline gives to favored others. Moreover, the promotion occurs at no detriment to the first objective, because no units of service are lost to the pipeline grid by disallowing the practice. </p>
<p align="left">In unbundling sales from transportation in 1992, the FERC took care to declare the Rate Design Policy Statement "still will be applicable to ... the discounting of rates."[Fn.16] Correction of the gas-on-gas, prejudicial rate methodology problem also would improve allocative and productivity efficiency under the Policy Statement, as encouraged by the Final Rule.[Fn.17] </p>
<h3 align="left"> The Remedy: Measures Less Severe on Captive Customers</h3>
<p align="left">The FERC's rule in Part 284 (Title 18 of the Code of Federal Regulations) requires that discounts, including gas-on-gas discounts, be provided without "undue discrimination or preference of any kind."[Fn.18] The Natural Gas Act "fairly bristles" with concern for undue discrimination that those regulations were issued to prevent.[Fn.19] Section 4 (b)(2) of the Act proscribes illegal discrimination as taking place between "classes of service."[Fn.20] Disallowing such prejudicial ratemaking also would be appropriate under the FERC's long-standing doctrine stating that the only legal rate is the FERC-filed rate.[Fn.21] </p>
<p align="left">Rather than await a court challenge, the FERC could well accommodate some of the gains[Fn.22] it seeks in its discounting policy through means less severe on captive customers. The FERC should correct the discrimination inherent in its current model for rate discounting by these two measures: </p>
<p align="left"><b>No undercutting the reservation charge.</b> Gas-on-gas discounting of reservation charges below the filed maximum reservation charges of a competing, FERC-regulated pipeline should not be allowed. Nor should adjustments for any permissible gas-on-gas discounting of the reservation charge be allowed in the design of rates. Pipelines could discount down to another pipeline's maximum reservation charge, but without standard model rate design privilege of recouping those discounts from other customers. </p>
<p align="left"><b>No discounting the usage charge.</b> Gas-on-gas discounting of usage charges in firm rates also should not be allowed. Nor should any discounting of interruptible rates below usage charges of a competing, FERC-regulated pipeline, or any discounting of interruptible rates to compete with capacity released by a firm service customer of a FERC-regulated pipeline, be allowed. Pipelines could discount down to another pipeline's filed firm or interruptible usage charge, but, again, without rate design privilege. </p>
<p align="left">At the end of the day, the Final Rule pays lip service to "reduced discount adjustments,"[Fn.23] but lifts not a finger to ease the gas-on-gas problem, let alone cure it. The FERC should assure that price differentials among transportation customers will benefit captive customers equitably by making a contribution to fixed costs that otherwise will not be made at all. Because no such assurance for gas-on-gas discounting exists, the FERC, or the courts on appeal, should take away the standard model rate design toy for playing that zero-sum game. There is no excuse for continuing to duck this matter. </p>
<p align="left"></p>
<p align="left"></p>
<p align="left"><b>FOOTNOTES:</b> </p>
<p align="left">1. Regulation of Short-Term Natural Gas Transportation Services, and Regulation of Interstate Natural Gas Transportation Services, Order No. 637 Final Rule, FERC Stat. &amp; Reg. ¶31,091. </p>
<p align="left">2. Adjusting ratemaking throughput is a mathematical step in the rate-setting process that takes the revenue requirement allocated to customers not receiving discounts and spreads it over a smaller throughput volume of gas, thus resulting in a higher unit rate for transportation. </p>
<p align="left">3. Regulation of Interstate Natural Gas Transportation Services, Notice of Inquiry, FERC Stat. &amp; Reg. ¶35,533 at 35,744. </p>
<p align="left">4. Final Rule, supra, FERC Stat. &amp; Reg. ¶31,091 at 31,267. </p>
<p align="left">5. FERC analysis says, where it is clear the discount is solely at the pipeline's expense, selective discounts will not "ordinarily" be discriminatory; however, "[c]omplaints will be entertained as a means of determining whether a particular discount is pernicious." Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol, Order No. 436-A, FERC Stat. &amp; Reg. ¶30,675, 31,679-80 (1985). </p>
<p align="left">6. Koch Gateway Pipeline Co., 84 F.E.R.C. ¶61,143, 61,779-80 &amp; n.57 (1998); Panhandle Eastern Pipe Line Co., 74 F.E.R.C. ¶61,109, 61,404 &amp; n.117 (1996). </p>
<p align="left">7. Final Rule, supra, FERC Stat. &amp; Reg. ¶31,091 at 31,271. </p>
<p align="left">8. Id. &amp; n.82; see also at 31,274-75. However, nothing in the court decision, comments, or treatise cited in the Final Rule considers that not one more dekatherm flows in the grid because of gas-on-gas discounts. To the contrary, the cited treatise says price discrimination is justified by "making fuller use of existing capacity," which does not happen across the grid due to gas-on-gas discounting. 1 A. Kahn, The Economics of Regulation 133 (1970). </p>
<p align="left">9. Mississippi Valley Gas Co. v. FERC, 68 F.3d 503 (D.C. Cir. 1995)(at 507: "[T]he agency has decided to allow selective discounting to meet gas-on-gas competition"); accord Williston Basin Interstate Pipeline Co., 85 F.E.R.C. ¶61,247, 62,028-30 (1998)(at 62,029: "[D]iscounts are also permitted to meet competition from alternate natural gas pipelines"). </p>
<p align="left">10. Southern Natural Gas Co., 67 F.E.R.C. ¶61,155, 61,457 (1994)(two-thirds of discounts assertedly for gas-on-gas competition). </p>
<p align="left">11. Associated Gas Distributors v. FERC, 824 F.2d 981, 1010-11 (1987), cert. denied, 485 U.S. 1006 (1988). </p>
<p align="left">12. Id. at 1011-12. </p>
<p align="left">13. Mississippi Valley, supra, 68 F.3d at 507. </p>
<p align="left">14. United Distribution Cos. v. FERC, 88 F.3d 1105, 1142 (D.C. Cir. 1996), cert. denied, 520 U.S. 1224 (1997). </p>
<p align="left">15. Interstate Natural Gas Pipeline Rate Design, et al., 47 F.E.R.C. ¶61,295, 62,056-57, order on reh'g, 48 F.E.R.C. ¶61,122 (at 61,449: FERC has a "policy of avoiding cross-subsidizations"). </p>
<p align="left">16. Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation; and Regulation of Natural Gas Pipelines After Wellhead Decontrol, Order No. 636, FERC Stat. &amp; Reg. ¶30,939, 30,434. </p>
<p align="left">17. Final Rule, supra, FERC Stat. &amp; Reg. ¶31,091 at 31,262 &amp; n. 71. </p>
<p align="left">18. 18 C.F.R. §§284.7 (b), 284.9 (b), effective March 27, 2000; Final Rule, supra, FERC Stat. &amp; Reg. ¶31,091, 65 Fed. Reg. 10,156, 10,219-20. </p>
<p align="left">19. Associated Gas Distributors, supra, 824 F.2d at 998. </p>
<p align="left">20. 15 U.S.C. §717c (b)(2). </p>
<p align="left">21. Montana-Dakota Utilities Co. v. Northwestern Public Service Co., 341 U.S. 246, 251 (1951); see also Maislin Industries, U.S. v. Primary Steel, 497 U.S. 116, 126-36 (1990); MCI Telecommunications Corp. v. American Telephone and Telegraph Co., 512 U.S. 218, 234 (1994). </p>
<p align="left">22. Associated Gas Distributors, supra, 824 F.2d at 1010. </p>
<p align="left">23. Final Rule, supra, FERC Stat. &amp; Reg. ¶31,091 at 31,263-64. </p>
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Sat, 15 Apr 2000 04:00:00 +0000puradmin10647 at http://www.fortnightly.comPerspectivehttp://www.fortnightly.com/fortnightly/1999/01-0/perspective
<div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Philip M. Marston</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - January 15 1999</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p> Want auctions for gas capacity? Don't think pipeline. Think online. </p>
<p> In July 1998, the Federal Energy Regulatory Commission signaled its intent to try one more time to make greater use of electronic auctions in the pricing and allocation of regulated gas pipeline transmission capacity. The proposed rule, issued in Docket No. RM98-10, marks the third major effort by the commission in this area. Several workshops have already been held. Formal comments are due Jan. 22. </p>
<p> Since the commission began in 1992 to encourage electronic markets for pipeline capacity, several private ventures have sought to create trading products. None has succeeded, however. The publicly reported losses of those who tried are measured in the tens of millions of dollars. </p>
<p> Nevertheless, while private auctions for regulated transmission capacity have failed, auctions in closely related, but freely tradable unregulated commodities have succeeded quite nicely. Today, AltraTM Streamline and QuickTrade's Power Trading System, which provide electronic auctions for natural gas at a variety of delivery points, are known and accepted industry institutions. </p>
<p> Moreover, since the commission last examined the use of auctions, electronic merchants and auctioneers on the World Wide Web have begun to redefine the roles of buyers and sellers. They are radically changing conceptions of how business is conducted, including such fundamental questions as what "inventory" is and who provides it. The question of "where" a business even exists becomes problematic. Over time, these new virtual merchants will change the very physical landscape in which we live and work. </p>
<p> Accordingly, as the commission considers possible regulatory changes involving electronic auction markets, it may find it valuable to understand why its prior efforts to encourage electronic auction markets in capacity have failed, and why other electronic markets and auctions have succeeded. In particular, the commission should be attentive to the experience of online merchants and auctioneers in unrelated commodities. It should stay open to lessons that may apply as well to the regulated gas industry. This article is intended to help open the public discussion of these complex, important matters. </p>
<p> Redefining the Bounds of the Possible </p>
<p> Politics, it's been observed often, is the art of the possible. What happens, though, when the range of possibilities is suddenly and radically redefined in totally unanticipated ways? This question will come before the FERC this year in its pending auction inquiry. </p>
<p> What is already uncontestable is that the technological and institutional revolution known as the Internet is radically remaking the bounds of the possible in commercial transactions. In 1992, when Order No. 636 was issued, the World Wide Web barely existed. It has been estimated that there were only about 50 "http" servers in existence in January 1993.fn1 During the ensuing five years, while the gas industry has focused on creating and refining its institutional structures and business processes to make open access to the gas grid a success, the World Wide Web has been working radical changes in the way buyers and sellers interact in the rest of the commercial world. </p>
<p> The extent of this change is reflected in the valuations applied to the securities of those companies that are viewed as mastering the new model. In mid-November, one of the best-known cyber-merchants, Amazon.com, was sporting a market capitalization of approximately $9 billion. The online auction company, eBay Inc., was valued at a little less than $6 billion. To put these numbers into perspective, consider that Amazon would be valued considerably higher than all of the gas distribution utilities in the Commonwealth of Massachusetts, combined. The market values of Amazon and eBay together would exceed the market capitalization of Pacific Gas &amp; Electric Company. Consider further that the online merchants have been in business for, at most, about three years - while the gas distribution business began operating in Massachusetts in the 1820s, which is to say, during Thomas Jefferson's retirement. </p>
<p> It would be foolish to try to predict exactly how these changes will play out in the coming decades. What already is clear, however, is that the ability to exchange and transfer information in the new ways is working radical changes in the way ordinary business transactions are carried out. These changes have clear implications for commission policy involving the natural gas and electric power industries. </p>
<p> One simple example may help illustrate how electronic communication can revolutionize something as simple as "inventory." </p>
<p> It used to be that a merchant kept available in the store (typically on the premises) a certain quantity of the goods to be sold. This practice allowed the customer to view the goods as well as to take possession upon sale. In the 19th century, Sears, Roebuck and Co. pioneered a revolution in marketing by putting drawings of its goods in a catalog and distributing the catalog widely via the mail. This business model (updated to substitute the hand-drawn sketches with photographs) is still used commonly by a great many specialized merchants. </p>
<p> In the years after World War II, the "discounter" appeared. The discounter took advantage of the radical change created by the automobile, which brought distant suburbs - and cheap, undeveloped land - into easy reach. Relying on these changes, the discounters began constructing ever-larger stores at ever-greater distances from established population centers. This development reached a reductio ad nauseum in the "category killer" store, one that sought to have on hand an extraordinary inventory of nearly all goods of a certain kind. During the last 50 years, these trends (reinforced, of course, by zoning, tax and various other policy incentives) have brought us cheap prices with expanded consumer choice - plus unrelenting suburban sprawl. </p>
<p> The cyber-merchants are preparing to send a multi-ton wrecking ball swinging through this business model. Under the Amazon business model, the bulk of the inventory cost is carried by the producer or distributor of the good, not the retail merchant. The concepts of "warehouse" and "inventory" fall under attack. The need for cheap land and plentiful parking must be profoundly re-thought. </p>
<p> This shift was made exceptionally concrete to this author when, one quiet midnight in 1997, he listed a self-published adventure novel with Amazon's online catalog - thereby integrating the unsold books in his attic inventory into Amazon's worldwide cyber-warehouse. The scope of the changes resulting from the business models was driven further home in late 1998 when he received an order from Amazon's competitor, Barnes and Noble. To his astonishment, the author discovered that the unsold books that lay in his attic had somehow been listed in a second worldwide catalog, this time without his having done a thing to list the book there. </p>
<p> Like Darwin staring at fossilized fishes 12,000 feet above the blue Pacific, I was struck by a colossal discontinuity. Today, in the new distribution/marketing business, the availability of cheap, well-organized information is replacing cheap green suburban fields. Evanescent electrons begin to substitute for a concrete pad, steel beams and a parking lot - not to mention tires, gasoline and a few fast food joints. </p>
<p> Creating a Well-Lit Marketplace </p>
<p> First-generation cyber-merchants such as Amazon continue to buy goods from suppliers and resell them at retail to consumers. Other businesses, however, are pushing the model one step further. </p>
<p> eBay, for example, has created what might be termed a "pure auction" business. eBay never owns the goods at any point in the transaction. Instead, it serves merely as the humble meeting place for the buyers and sellers to get together - something like the role played by New York, Paris, Rome and London. The auction business tries to provide a convenient, well-lit marketplace. It enforces a few basic ground rules for buyers and sellers, earning commissions on each transaction. These are fees that might have been called "rent" under the older business model. </p>
<p> A variant - or rather, a complement - of both the cyber-merchant and cyber-auction models is the electronic comparison business model. Here, the service provider merely offers an electronic tool for comparing prices and terms set elsewhere. Already evident is a variety of such services, including CompareNet (<a href="http://www.compare.net">www.compare.net</a>) and others. In its simplest form, this variant is merely a service that surveys publicly available prices and presents them in a side-by-side comparison. These sites serve a market-policing function, enabling buyers and sellers to learn what prices are available in other transactions. These sites may grow into purchasing cooperatives as well, as appears to be a goal of such companies as electricitychoice.com and energy.com. </p>
<p> Importantly, an auction house such as eBay has every reason to design and operate a fair and efficient marketplace. Since the auctioneer makes money from successful listings, it has every incentive to encourage buyers and sellers to return time and again to its marketplace. Obviously, that means first and foremost maintaining the integrity of the marketplace. Honesty is the only successful policy for a web-based merchant, since violations (both actual and suspected) are sanctioned in a New York nanosecond with a click of the mouse. </p>
<p> Righting Mistakes of the Past </p>
<p> Which of these merchant/auction models would work best for natural gas or electricity? The short answer, of course, is that no one knows, least of all the FERC. What we do know is that given the freedom to innovate, software designers and entrepreneurs have proven able in just a few short years to create businesses that are valued much more highly than regulated businesses born in the days of Thomas Jefferson. </p>
<p> Under this perspective, the key question the commission should be asking in the rulemaking proceeding is why the existing auction houses and cyber-merchants do not already offer auction services for pipeline capacity. It would soon learn that the reasons are rooted in the commission's prior rulings that define the transfer of such a right as a jurisdictional act for which the commission, as a matter of policy, will not grant a Natural Gas Act certificate. By prohibiting what it termed "capacity brokering," the commission sought to force posting all such transactions in the form of "releases" conducted on pipeline electronic bulletin boards. </p>
<p> Unfortunately, this policy posed a dilemma for potential buyers and sellers of capacity in a cross-pipeline market. They faced the prospect of having to re-post and re-consummate transactions as "releases" on disparate pipeline EBBs - deals that the parties had already conducted on the open auction board. Faced with inefficient pipeline-specific EBBs in any event, market support for the cross-pipeline auction boards evaporated. That drained the liquidity from the auction services and ensured their demise. </p>
<p> The second great obstacle to successful electronic auctions in capacity flowed directly from the first. By viewing auction transactions as jurisdictional and seeking to force traders through the grinder of pipeline-specific EBBs, the FERC discouraged the development of electronic tools for evaluating transmission paths across various pipeline systems. One of the key commercial problems an electronic auction mechanism seeks to solve is how to provide buyers with the ability to link segments that cannot readily be "seen" as linked (for example, because they involve non-contiguous segments of the same pipeline, non-contiguous pipelines or even different fuels). </p>
<p> Just as Amazon's electronic links allow a self-publisher to establish relational links between books in the attic and a school librarian, so a well-designed auction service should allow buyers, as an economic matter, to link paths on pipelines a thousand miles apart. While that is done today through privately negotiated swaps and basis differentials across pools, it is a relatively inefficient process. It lacks the transparency that would come from efficient cross-pipeline auction markets. </p>
<p> Moreover, as the electronic and energy markets mature and converge, sellers may seek ways to link things that the commission never dreamed would be joined in a single transaction. Examples might include the sale of light with books,fn2, gas with groceries,fn3, heat with mortgage servicing,fn4, or electricity with religious charities.fn5 In a nation of hundreds of millions, no one should expect everyone to want their molecules or electrons painted the same color. It bears remembering that insisting on producing a single-color automobile cost Henry Ford the dominant position in the U.S. automobile industry for decades. </p>
<p> The FERC need not renounce jurisdiction over capacity assignment for this innovation to proceed. All that is required is the withdrawal of that portion of the proposed rule that seeks to define by law the terms of the auction market. Instead, to the extent the commission believes its jurisdiction is implicated, it should issue a blanket certificate to any software company that designs, implements and operates an electronic auction mechanism that allows willing parties to transfer the rights to receive transportation service. The certificate could be made contingent on providing the commission with access to the audit trail of all jurisdictional transactions. </p>
<p> This approach gives the commission a valuable role: It is the FERC that takes responsibility for preventing abuse of a dominant position in the market - not the software developers. It also allows auction designers to modify the auction mechanism as necessary as experience is gained, without the need to conduct a formal rulemaking proceeding, while providing the commission with the real-time information that is required to respond to allegations of market abuse. </p>
<p> Some may argue that the commission lacks authority to remove the regulatory obstacles preventing the rapid development of electronic commerce in gas and electricity. But after all, the commission recently ordered a hydroelectric dam barring a small river to be removed; why not remove the regulatory dam across the Amazon? We know that since 1995, new industries worth billions of dollars have emerged from scratch to offer choices to consumers to buy what they want, when they want, for prices they want. Why bar the gas industry from this historic transition? </p>
<p> Philip M. Marston is an attorney and consultant who has written and spoken widely on regulatory issues affecting the natural gas industry. He conducts his energy law practice from Alexandria, Va. Marston's e-mail address is <a href="mailto:PMMARSTON@aol.com">PMMARSTON@aol.com</a>. </p>
</p>
<p> 1 "Http" stands for "hyper text transfer protocol." Http is the set of communications instructions that are used for the bulk of web communication. </p>
<p> 2 How about "Make a good book better - gentle light for tired eyes"? </p>
<p> 3 See netgrocer.com. </p>
<p> 4 Marketers already have experimented with such bill-consolidation efforts. </p>
<p> 5 The marketing slogan might be "Let There be Light." </p>
<p></p>
<p><center>22</center>
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Fri, 15 Jan 1999 05:00:00 +0000puradmin10786 at http://www.fortnightly.comLG&E?s Don Santa: Choice in a Low-Cost Statehttp://www.fortnightly.com/fortnightly/1998/06/lges-don-santa-choice-low-cost-state
<div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Lori M. Rodgers</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - June 1 1998</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p> IN APRIL 1997, AFTER FOUR YEARS AS A COMMISSIONER WITH the Federal Energy Regulatory Commission, Donald F. Santa, Jr. announced that he would leave the public sector at the expiration of his term and join LG&amp;E Energy Corp. as vice president and deputy general counsel. Included among his first assignments at LG&amp;E was management of legal matters for LG&amp;E Marketing, the national energy marketing subsidiary of LG&amp;E Corp. </p>
<p> Roger Hale, chairman and CEO for LG&amp;E Energy, praised Santa as "instrumental" in shaping the nation's energy policy and in "writing the ground rules for competition" in the energy industry. </p>
<p> Santa had begun his stint at the FERC when the commission was working hard at implementing Order No. 636, the natural gas restructuring rule, and thus had received an early grounding in gas issues. Later, when the FERC began tackling electric restructuring under its eventual Order 888, Santa drew on his gas experience, which he said gave him insight on gas-electric convergence issues. As he was fond of saying, "I was converging when converging wasn't cool." </p>
<p> As for his move to the private sector, Santa saw it as a chance to keep up with industry changes. "I have had the unique opportunity to be a member of the FERC during one of the most exciting periods in the agency's history," he noted. "Still, regulation is to some degree removed from the reality of the marketplace¼ Consequently, I am excited at the prospect of getting outside the Beltway¼ where the real changes are occurring." </p>
<p> As if to emphasize Santa's words, on March 25 has new employer won approval from the FERC for a merger with Kentucky Utilities, on assurances that the new company would, among other things, continue to participate in the Midwest Transmission System Operator, Inc. By May 4, LG&amp;E and KU announced that they had closed their merger "in record time" for a deal between two franchised electric utilities involving review under the FERC's 1996 merger policy statement. </p>
<p> Addressing a group of lawyers at an American Bar Association meeting, Santa saw it all as ironic. "As late as last July," he said, "I was voting on merger orders at the [FERC], and by last September, I was counseling [the two applicants] and preparing their section 203 application. If only I knew then what I know now." </p>
<p> Spending Shareholder Dollars </p>
<p> LG&amp;E is a new member of the Partnership for Customer Choice. What led to this decision? </p>
<p> LG&amp;E hasn't been a member of the Edison Electric Institute for about two years. I think our CEO, Roger Hale, said the company didn't want to be spending LG&amp;E's shareholder dollars promoting a message on restructuring that he didn't think was LG&amp;E's message. Hale advocated a federal choice mandate with a date shortly after the year 2000, and supports a comprehensive restructuring bill. When I joined the company last fall, one of the things that was put on my "to do" list was to identify ways that the company could more effectively participate in the restructuring debate. When LG&amp;E surveyed the alternatives, the Partnership for Customer Choice came to our attention. PCC members are a lot of the more pro-competitive¼ and when we put the LG&amp;E position side by side with the PCC's principles they were remarkably alike. So we decided this was probably the most effective way for us to participate. </p>
<p> Is Dec. 15, 2000 still a realistic goal now that it's already 1998? </p>
<p> I don't think anything is locked in concrete, and I think that if and when it comes time for the horse trading that goes in to writing legislation, it's certainly something that could be on the table. I think you have to be sensitive to the fact that as the states move forward and as they commit to dates some of them may have phase-ins that go beyond Dec. 15, 2000. [Legislation] might have to grandfather what the states have done. PCC went with the date that was in Rep. Dan Schaefer's (R-Colo.) bill. I think it [made] a statement in terms of a commitment towards wanting choice sooner rather than later. </p>
<p> Too Many Mergers? </p>
<p> Will we eventually see a shake out down to five to ten giant utilities and energy providers, with all the recent mergers? [At the time of the interview, the FERC had not yet announced its approval of the LG&amp;E-Kentucky Utilities merger.] </p>
<p> The conventional wisdom, and I think it's well supported, is that in a restructured industry, scope and scale are going to be important, especially in those aspects of the business that are going to be competitive, so I think you're probably going to see a further consolidation of industry. It's premature to speculate on the ultimate number but I think that you're probably going to see further consolidations dictated by the need for scope and scale in order to be competitive. This doesn't preclude the further vertical disaggregation of the industry as people decide what part of the business that want to be in. It doesn't preclude there being niche players, although they may not be a huge nationwide player. </p>
<p> Will that be best for customers? Won't it reduce choices? </p>
<p> Consumers are ultimately going to benefit from a number of strong companies that have the wherewithal to go out there and basically beat each other over the head, ultimately to the benefit of the consumer. You can say, "the more competitors the better," but the companies need to have the wherewithal to be in it for the long haul. That gets back to the point of scope and scale: There are going to be certain economies of size that will dictate that to be a big player, and certainly a big player nationally, [companies will] need a certain critical mass. If it got to a point where the industry became so consolidated that you only had two or three players really competing, yes, you've got a problem, but we are a long, long way from seeing that happen. </p>
<p> On Returning to the Private Sector </p>
<p> A recent international survey of utility executives by Andersen Consulting found that more than half of the respondents felt that regulators don't understand or recognize their companies' investments. Do you agree? </p>
<p> I don't know. When I was at the commission I made an effort to try to get more up on how the financial community viewed things, talking with analysts in New York¼ but if this is what companies believe, they need to take the initiative to change it. Try to educate the regulators and try to have them understand the financial constraints and conditions that the company is operating under. Now, it remains to be seen what kind of impact it will have, but the recent FERC technical conference on financial conditions in the natural gas pipeline industry is a good step in trying to get that kind of input in there. When you're a regulator, and you're subject to the ex parte rules and all that, what you see in the record of a case is pretty much limited to what you see on paper, and usually the financial community doesn't participate as intervenors in a case. </p>
<p> How do you view the role of regulator now that you're on the other side? </p>
<p> I would hope that regulators take the view that I tried to take when I was at the [FERC], which was to recognize that there are certain segments of the industry [that] still are effectively monopolistic in function and need regulation, but by the same token you have to have some trust in the market with respect to those segments that either are or have the potential to be competitive. </p>
<p> You've got to try and put the incentives in the right place to get people to be efficient. I also think, and this is something I appreciate much more from having been in the industry for [a few] months, that with the market being as fast paced as it is, the delay in getting word from regulators really does hurt, it really does make a difference as people are trying to adapt to what's going on out there. A merger like ours, which isn't one of the biggest mergers sitting out there, nonetheless affects real people in terms of trying to figure out where they're going to be in the new company. There's a role for regulation (em you want to review these things carefully and responsibly (em but by the same token there has to be a recognition that delay brings with it very real-world costs. </p>
<p> Recently, at an American Bar Association conference in Denver, I was talking with a lawyer who does work for PacifiCorp, and he was talking about their transactions with The Energy Group. He mentioned that when the mergers and monopolies commission in Britain receives a merger application they schedule it for decision. It may be [several] months off, but they basically say, "You'll have an answer by this date." And then they commit themselves to doing it. I know that the FERC is strapped resource-wise and has to "do more with less," given budgetary constraints, but nonetheless I think there's some real importance to having word from the regulators, whether it be good or bad, so that people can get on with their businesses. It's hard to say what the average time frame for waiting to hear from FERC is, because the applications received in the 1995-96 time frame [prior to the 1996 Policy Statement] in some ways got held up because the merger policy was in a state of flux. There were some mergers that probably took almost two years to go through the process. Even understanding and knowing first-hand where the commission sat at that time and all the difficulties we had, people were being affected by this. </p>
<p> In the Merger Policy Statement the commission committed that if someone should file a complete application and there are not significant protests of that application, the commission would try to act within 60 to 90 days of the closing of the intervention and comment period. If that's a realistic deadline I really don't know, but I think the commission ought to commit to trying to get through these things in a realistic time frame. </p>
<p> Editor's Note: On April 16 the FERC issued a new notice of proposed rulemaking on mergers, in part to speed up approval. See Docket No. rm98-4-000, 83 ¶ FERC 61,027. </p>
<p> Lori M. Rodgers is contributing editor to Public Utilities Fortnightly. </p>
</p>
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<p><center>62</center>
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<a href="/tags/commission">Commission</a><span class="pur_comma">, </span><a href="/tags/edison-electric-institute">Edison Electric Institute</a><span class="pur_comma">, </span><a href="/tags/federal-energy-regulatory-commission">Federal Energy Regulatory Commission</a><span class="pur_comma">, </span><a href="/tags/ferc">FERC</a><span class="pur_comma">, </span><a href="/tags/it">IT</a><span class="pur_comma">, </span><a href="/tags/lge">LG&amp;E</a><span class="pur_comma">, </span><a href="/tags/order-888">Order 888</a><span class="pur_comma">, </span><a href="/tags/order-no-636">Order No. 636</a><span class="pur_comma">, </span><a href="/tags/pacificorp">PacifiCorp</a><span class="pur_comma">, </span><a href="/tags/transmission">Transmission</a> </div>
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Mon, 01 Jun 1998 04:00:00 +0000puradmin9807 at http://www.fortnightly.comCourts & Commissionshttp://www.fortnightly.com/fortnightly/1997/12/courts-commissions
<div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Phillip S. Cross</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - December 1997</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p> WITH DIRECT ACCESS SCHEDULED TO BEGIN ON Jan. 1, 1998, California regulators are moving quickly to set up their long-considered policies on electric restructuring. The restructuring actions touch nearly every aspect of electric regulation in the state from financing decisions and rate design to the sale of generating assets and monitoring new capital additions. </p>
<p> In addition, restructuring has affected ongoing regulatory activities such as the development of performance-based rate making plans and pricing and rate designs for large incumbent utilities. </p>
<p> Sale of Generation Assets </p>
<p> Southern California Edison wants to divest itself of its 12 gas-fired plants while Pacific Gas &amp; Electric Co. will sell three separate plants representing 45 percent of its fossil fuel generating capacity. Two years ago, the commission had ruled that the utilities should voluntarily divest themselves of at least 50 percent of their fossil fuel generating capacity. See, Re Proposed Policies Governing Restructuring California's Electric Services Industry and Reforming Regulation, 166 PUR4th 1 (Cal.P.U.C.1995). </p>
<p> Now, while authorizing each utility to "commence an auction" of plants, the commission has said it will review the final bids to determine whether the sales will harm either the reliability of the state's electric system or development of competition. Re Pacific Gas &amp; Electric Co., Decision 97-09-046, a. 96-11-020, Sept. 3, 1997 (Cal.P.U.C.); Re Southern California Edison Co., Decision 97-09-049, a. 96-11-046, Sept. 3, 1997 (Cal.P.U.C.). </p>
<p> Capital Additions </p>
<p> The commission also has reviewed past and future expenditures for non-nuclear capital additions put into service by Pacific Gas &amp; Electric, Southern California Edison and San Diego Gas &amp; Electric Co. At issue are generating costs incurred by the utilities to improve plant performance or to maintain system reliability. Earlier, the commission had issued separate decisions for rate making treatment of the state's three major nuclear generating plants: San Onofre (Decision 96-01-011), Palo Verde (Decision 96-12-083) and Diablo Canyon (Decision 97-05-088). </p>
<p> Generally, recovery of generation-related costs are not guaranteed under AB 1890, the state's electric restructuring law enacted in 1996. When the new market structure was developed, it was thought utilities might make expensive improvements to generating facilities to enhance their market positions. </p>
<p> The commission has now said each utility must file applications for recovery of any 1996 or 1997 capital costs in a competition transition charge. But before a utility can recover the costs, each expenditure must be reviewed for consistency with past capital budgets, cost effectiveness and operating performance. Re Proposed Policies Governing Restructuring California's Electric Services Industry and Reforming Regulation, Decision 97-09-048, R.94-04-031, I.94-04-032, Sept. 3, 1997 (Cal.P.U.C.). </p>
<p> Revenue Reduction Bonds </p>
<p> The commission has authorized Southern California Edison, Pacific Gas &amp; Electric, and San Diego Gas &amp; Electric Co. to issue to issue rate reduction bonds. The commission said Pacific Gas &amp; Electric could issue $3.5 billion aggregate principal amount of the bonds; Southern California Edison $3 billion, and San Diego Gas &amp; Electric $800 million. </p>
<p> The revenue requirement reduction produced by the bonds will give the small user a 10-percent rate reduction through a rate-freeze period as established under AB 1890. Under the approved financing plans, each utility will create a wholly owned subsidiary, which is intended to create a separate legal entity whose only business is to own transition property. The assets of the special purpose entity are not available to satisfy the debts incurred by the utility. Each utility will capitalize the new entity with equity in an amount equal to approximately 0.5 percent of the principal amount of rate reduction bonds to be issued. These "securitization" transactions are intended to allow for the substitution of lower-interest, longer-term secured obligations for higher-interest, shorter-term obligations. Re Pacific Gas &amp; Electric Co. et al., Decision 97-09-054, a97-05-006 et al., Sept. 3, 1997 (Cal.P.U.C.); Re Pacific Gas &amp; Electric Co., Decision 97-09-055, a97-05-006 et al., Sept. 3, 1997 (Cal.P.U.C.); Re Southern California Edison Co., Decision 97-09-056, a. 97-05-018, Sept. 3, 1997 (Cal.P.U.C.); Re San Diego Gas &amp; Electric Co., Decision 97-09-057, a97-05-022, Sept. 3, 1997 (Cal.P.U.C.). </p>
<p> PBR Plans </p>
<p> Restructuring also has affected several rate making matters not strictly related to restructuring. In one case, the commission granted, in part, a request by the state's Office of Ratepayer Advocate to suspend incentives in San Diego Gas &amp; Electric's experimental performance-based rate mechanism. Some electric price performance rewards and penalties contained in the plan clashed with the rate freeze mandated under the restructuring law. </p>
<p> The utility's PBR plan included a system of shareholder rewards and penalties intended to give managers incentives to improve the company's performance as measured by rates, employee safety, system reliability and customer satisfaction. While finding that the "non-price" incentives for safety, reliability and customer satisfaction might remain useful, the commission has now ruled that the incentive tied to the utility's rates should be suspended. Re San Diego Gas &amp; Electric Co., Decision 97-09-052, a.92-10-017, Sept. 3, 1997 (Cal.P.U.C.). </p>
<p> Rate Design </p>
<p> In another ruling, the commission required Pacific Gas &amp; Electric to refrain from discounting any component of its current rates except its distribution charge. As part of a scheduled rate design review, the company had proposed several new tariff options to take effect before competition to discount rates to "help avoid uneconomic bypass of PG&amp;E's transmission and distribution system." Upon review, the commission said the new rate schedules would stymie competition, because direct access service providers would not be able to offer competitive discounts. Re Pacific Gas &amp; Electric Co., Decision 97-09-047, a.94-12-005, Sept. 3, 1997 (Cal.P.U.C.). </p>
<p> LABOR FAILS TO ALTER METER UNBUNDLING </p>
<p> The Pennsylvania Public Utility Commission has rejected a bid by an electric industry union to block new generic PUC policy that could open up certain electric metering functions to competitive firms. </p>
<p> Nevertheless, the PUC said the union could raise its concerns again in upcoming dockets for approval of company-specific restructuring plans. </p>
<p> The union, the International Brotherhood of Electrical Workers, challenged a July PUC order that had stated that competitive firms might provide "nonphysical" metering services (although distribution utilities would continue to perform all physical metering functions). That order also required electric utilities to propose plans for optional single-source billing and complaint resolution by competitive energy firms, for those customers electing a competitive supplier. See, Docket No. m-00960890, July 11, 1997, 178 PUR4th 469. </p>
<p> According to the union, the PUC had failed to meet legal requirements under the state public utility code and the state's recently enacted electric industry restructuring law, which require the commission to maintain customer service standards at "existing levels" under retail competition. </p>
<p> The union had argued that an electric utility cannot fulfill existing service obligations if it does not continue to own, maintain and read meters and issue the resulting bill for service. Re Guidelines for Maintaining Customer Services, Docket No. m-00960890 f 0011, Aug. 2, 1997 (Pa.P.U.C.). </p>
<p> PENNSYLVANIA ADOPTS ELECTRIC MARKETING RULES </p>
<p> The Pennsylvania Public Utility Commission has adopted interim price disclosure requirements for electric utilities, competitive suppliers and aggregators or brokers who participate in the state's newly restructured electric market. </p>
<p> The rules will ensure that customers are provided with enough information to compare prices and services between competitive suppliers uniformly. </p>
<p> Under the rules, customer bills must show separate rate components including: generation, transmission, distribution and transition charges. In addition, the first page of a customer bill must also contain usage information, including twelve-month total usage figures and a monthly average. Suppliers must also give customers a comparison of existing monthly cost for basic services and any new pricing agreements it has offered. </p>
<p> To avoid problems with marketing "green" power alternatives, the commission adopted specific requirements to identify energy sources. It noted that suppliers who knowingly misrepresent environmental benefits would be subject to claims of fraud and breach of contract under state law. Re Electric Generation Customer Choice and Competition Act - Customer information - Interim requirements, Docket No. m-00960890f0008, July 11, 1997 (Pa.P.U.C.). </p>
<p> NEW JERSEY APPROVES GAS DISCOUNT RATE </p>
<p> The New Jersey Board of Public Utilities has allowed South Jersey Gas Co. to offer significant discounts to one of its large industrial customers that had threatened to leave the local gas system to lower its supply costs. </p>
<p> The utility said that the customer, Huntsman Polypropylene Corp., had considered bypassing the South Jersey system through a direct connection with Columbia Gas Transmission Corp., an interstate pipeline company. Huntsman also had considered closing its chemical manufacturing facilities in the area. Re South Jersey Gas Co., BPU Docket No. gt96090690, Aug. 27, 1997 (N.J.B.P.U.). </p>
<p> TELCO FAILS FCC CHECKLIST FOR COMPETITION </p>
<p> The Illinois Commerce Commission has found that Illinois Bell Telephone Co. failed to meet federal requirements that would allow the carrier to compete in the interLATA long-distance market. </p>
<p> The commission said Illinois Bell had satisfied requirements concerning interconnection offerings to competitors and that it was providing unbundled loops to requesting parties at an appropriate level of quality. The commission said, however, that while the carrier's network offerings were working, the operational support of the system (i.e., ordering, maintenance and repair and billing functions) had sufficient bugs to give customers of competing carriers the impression that they were receiving inferior service. </p>
<p> Under the federal Telecommunications Act of 1996, state regulators must review progress by local exchange carriers in opening the local telephone network to competitors using a "checklist" developed by the Federal Communications Commission. The list checks to see whether an LEC has opened its own system to competition enough to justify allowing it to compete against long-distance carriers. </p>
<p> The checklist includes the requirement that the LEC must provide access and interconnection services to "one or more unaffiliated competing providers of telephone exchange service¼ to business and residential subscribers." Re Illinois Bell Tel. Co., No. 96-0404, Aug. 4, 1997 (Ill.C.C.). </p>
<p> WATER UTILITY LOSES BIDFOR EXCLUSIVE TERRITORY </p>
<p> The Indiana Utility Regulatory Commission has ruled there is no basis under state law to grant exclusive service territories to water utilities. </p>
<p> The commission had authorized Indiana-America Water Co. to continue to provide water service to a residential subdivision in an area already served by another utility. Indiana-American began serving the new customers after negotiating a main extension agreement with the developer of the subdivision. </p>
<p> The incumbent utility in the area, Flowing Wells Inc., a subsidiary of Citizens Utilities Co., had claimed that it was located better to serve the area and that its rates were lower than Indiana-American. It also said its existing customers would benefit from the new customers. The utility had asked the commission to declare that it had an exclusive right to serve the residential area. </p>
<p> The commission said that it could find no statutory basis to grant exclusive territories or to draw boundary lines to resolve disputes between water utilities. Re Flowing Wells Inc., Case No. 40446, July 16, 1997 (Ind.U.R.C.). </p>
<p> KN TO EXPAND RETAIL CHOICE </p>
<p> Although customers have complained about their bills, the Wyoming Public Service Commission has allowed KN Energy Inc. to expand its choice program, explaining that most participants have experienced significant savings. </p>
<p> The commission said the program's "facilities charge" - which allows the LDC to recover non-gas costs of delivering supplies to participating customers - had created customer confusion and complaints. It ordered the company to increase its efforts to educate customers, and to provide bill verification services and improve the format of the bill. Re KN Energy Inc., Docket No. 30004-gt-95-37, April 24, 1997 (Wyo.P.S.C.). </p>
<p> The commission found that nearly 95 percent of customers in the Choice Gas Service Program had saved 7 percent to 12 percent on their energy bills. The program was first approved by the commission in early 1996 (See, Re KN Energy Inc., 169 PUR4th 1 (1996).) </p>
<p> OHIO COURT OKs SUB-COST CONTRACT </p>
<p> The Ohio Supreme Court has overturned a ruling by the Ohio Public Utilities Commission that had barred Ohio Edison from providing cooling-load power to a county jail below cost. </p>
<p> The court found that state law statute (R.C. 4905.33) allows a public utility to grant reduced-rate utility service to a political subdivision, such as the county jail. It said such authority was not limited by the statute, which prohibits below-cost utility service contracts. Ohio Edison Co. v. Ohio PUC, et al., No. 95-2575, 678 N.E.2d 922, 78 Ohio St.3d 466, May 21, 1997 (Ohio). </p>
<p> The commission earlier had ruled Ohio Edison had violated the statute by providing cooling-load power to a county jail below-cost. See, Youngstown Thermal, Ltd. Partnership v. Ohio Edison Co., 163 PUR4th 471 (Ohio P.U.C.1995); and Youngstown Thermal Ltd. Partnership v. Ohio Edison Co., 165 PUR4th 135 (Ohio P.U.C.1995). </p>
<p> IN BRIEF.... </p>
<p> GAS STORAGE COSTS. Maine revises gas cost adjustment rules to allow recovery of off-system storage costs. Commission explains current rules exclude all storage costs from recovery, but since FERC Order No. 636, the industry treats storage costs as a gas supply cost. Docket No. 97-172, Aug. 6, 1997 (Me.P.U.C.). </p>
<p> Diversification. Michigan certifies plan by MCN Energy Group Inc. to increase investments in electric generation facilities in India to $500 million. Case No. U-11373, Sept. 12, 1997 (Mi.P.S.C.). </p>
<p> Pipeline Demand Costs. Pennsylvania upholds use of the "extra demand" method for allocation of interstate pipeline charges incurred by T.W. Phillips Gas and Oil Co. The method allocates costs based on each customer class' contribution to peak-day demand above its average demand. R-00963812, July 31, 1997 (Pa.P.U.C.). </p>
<p> Upstream Gas Competition. Oregon OKs plan by Northwest Natural Gas Co. to offer competitive upstream commodity and capacity services outside its own service territory, finding markets had developed sufficiently. Order No. 97-342, Sept. 5, 1997 (Ore.P.U.C.). </p>
<p> Revamped Restructuring Plan. Montana says PacifiCorp's electric restructuring plan doesn't meet requirements of new customer choice law and orders utility to resubmit it. The PSC finds insufficient data on transition costs, separation of rate base and expense items and pilot programs. Docket No. D97.7, Order No. 5987b, Sept. 22, 1997 (Mont.P.S.C.). </p>
<p> Tort Liability Waiver. Illinois court rules that a tariff waiver of tort liability protected Commonwealth Edison Co. against damage claims by a customer who was injured in a fall after the utility disconnected power to her home. Disconnection was part of safety measures associated with the 1992 Chicago Tunnel Flood. No. 93 L 4338, Sept. 3, 1997 (Ill.Cir.Ct.). </p>
<p> Gas Service Territory. North Carolina Supreme Court upholds a decision by state regulators granting certificate of convenience and necessity to a newly formed company to provide natural gas service in previously unserved areas of the state. 488 S.E.2d 591, July 24, 1997 (N.C.) </p>
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<p><center>54</center>
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<a href="/tags/ces">CES</a><span class="pur_comma">, </span><a href="/tags/citi">Citi</a><span class="pur_comma">, </span><a href="/tags/commission">Commission</a><span class="pur_comma">, </span><a href="/tags/communication">Communication</a><span class="pur_comma">, </span><a href="/tags/cost">Cost</a><span class="pur_comma">, </span><a href="/tags/customer-information">Customer information</a><span class="pur_comma">, </span><a href="/tags/dc">DC</a><span class="pur_comma">, </span><a href="/tags/fcc">FCC</a><span class="pur_comma">, </span><a href="/tags/federal-communications-commission">Federal Communications Commission</a><span class="pur_comma">, </span><a href="/tags/ferc">FERC</a><span class="pur_comma">, </span><a href="/tags/gas">GAS</a><span class="pur_comma">, </span><a href="/tags/ge">GE</a><span class="pur_comma">, </span><a href="/tags/ice">ICE</a><span class="pur_comma">, </span><a href="/tags/illinois-commerce-commission">Illinois Commerce Commission</a><span class="pur_comma">, </span><a href="/tags/indiana-utility-regulatory-commission">Indiana Utility Regulatory Commission</a><span class="pur_comma">, </span><a href="/tags/it">IT</a><span class="pur_comma">, </span><a href="/tags/new-jersey">New Jersey</a><span class="pur_comma">, </span><a href="/tags/new-jersey-board-public-utilities">New Jersey Board of Public Utilities</a><span class="pur_comma">, </span><a href="/tags/northwest-natural">Northwest Natural</a><span class="pur_comma">, </span><a href="/tags/northwest-natural-gas">Northwest Natural Gas</a><span class="pur_comma">, </span><a href="/tags/ohio-edison">Ohio Edison</a><span class="pur_comma">, </span><a href="/tags/opt">OPT</a><span class="pur_comma">, </span><a href="/tags/order-no-636">Order No. 636</a><span class="pur_comma">, </span><a href="/tags/pacific-gas-electric">Pacific Gas &amp; Electric</a><span class="pur_comma">, </span><a href="/tags/pacificorp">PacifiCorp</a><span class="pur_comma">, </span><a href="/tags/pge">PG&amp;E</a><span class="pur_comma">, </span><a href="/tags/rec">REC</a><span class="pur_comma">, </span><a href="/tags/regulation">Regulation</a><span class="pur_comma">, </span><a href="/tags/san-diego-gas-electric">San Diego Gas &amp; Electric</a><span class="pur_comma">, </span><a href="/tags/san-diego-gas-electric-0">San Diego Gas &amp; Electric</a><span class="pur_comma">, </span><a href="/tags/southern-california-edison">Southern California Edison</a><span class="pur_comma">, </span><a href="/tags/storage">storage</a><span class="pur_comma">, </span><a href="/tags/transmission">Transmission</a> </div>
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Mon, 01 Dec 1997 05:00:00 +0000puradmin8232 at http://www.fortnightly.comMich. Examines Gas Brokering, Appliance Repairhttp://www.fortnightly.com/fortnightly/1997/07/mich-examines-gas-brokering-appliance-repair
<div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Phillip S. Cross</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - July 1 1997</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>The Michigan Public Service Commission has authorized Michigan Gas Utilities to increase rates and has ruled that revenues booked by an affiliate that offers administrative, gas brokering and appliance repair services should be included as part of the utility's net income.</p>
</p>
<p> The commission said Michigan Gas can increase rates $1.7 million, including an allowance for return on equity of 10.75 percent. </p>
<p> Michigan Gas had excluded from rate calculations revenues found unrelated to utility operations, such as an unregulated affiliate's propane operations. According to the commission, the affiliate has no employees of its own for the services and relied on utility employees to perform the required tasks. </p>
<p> The commission also denied recovery of a portion of the costs allocated to the utility by its corporate parent, UtiliCorp United Inc., for centralized gas supply services as well as appliance repair training. It rejected claims by the utility that increased gas supply costs were attributable to changes in the structure of the gas market initiated by Federal Energy Regulatory Commission in Order No. 636. </p>
<p> The utility had failed to show how ratepayers benefitted from the increased costs associated with the centralized gas supply arrangement, the commission said. It also found that the benefits to the utility from training its employees in gas and electric appliance repair was "incidental at best" and instead was provided primarily so that those employees might be able to perform repair service on behalf of to company's unregulated affiliate. Re Michigan Gas Utils., Case No. U-10960, March 27, 1997 (Mich.P.S.C.). t </p>
<p> Phillip S. Cross is an associate legal editor of PUBLIC UTILITIES FORTNIGHTLY. </p>
</p>
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<p><center>49</center>
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<a href="/tags/commission">Commission</a><span class="pur_comma">, </span><a href="/tags/federal-energy-regulatory-commission">Federal Energy Regulatory Commission</a><span class="pur_comma">, </span><a href="/tags/it">IT</a><span class="pur_comma">, </span><a href="/tags/michigan-public-service-commission">Michigan Public Service Commission</a><span class="pur_comma">, </span><a href="/tags/order-no-636">Order No. 636</a> </div>
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Tue, 01 Jul 1997 04:00:00 +0000puradmin10269 at http://www.fortnightly.com